GEK-106290D
GE
Digital Energy
489
Generator Management
Relay
SELECT CURVE STYLE:
Voltage Dependent
489 STATUS
GENERATOR STATUS
OUTPUT RELAYS
489 IN SERVICE
BREAKER OPEN
R1 TRIP
SETPOINT ACCESS
BREAKER CLOSED
R2 AUXILIARY
COMPUTER RS232
HOT STATOR
R3 AUXILIARY
COMPUTER RS485
NEG. SEQUENCE
R4 AUXILIARY
AUXILIARY RS485
GROUND
R5 ALARM
ALT. SETPOINTS
LOSS OF FIELD
R6 SERVICE
RESET
POSSIBLE
RESET
VT FAILURE
MESSAGE
NEXT
PROGRAM PORT
BREAKER FAILURE
SETPOINT
7
8
9
4
5
6
1
2
3
.
0
HELP
MESSAGE
ACTUAL
ESCAPE
VALUE
ENTER
g
489 Generator Management Relay
TM
808754E4.CDR
GE Digital Energy
650 Markland Street
Markham, Ontario
Canada L6C 0M1
TELEPHONE: Worldwide +1 905 927 7070
Europe/Middle East Africa +34 94 485 88 54
North America toll-free 1 800 547 8629
FAX:
+1 905 927 5098
E-MAIL:
Worldwide multilin.tech@ge.com
Europe multilin.tech.euro@ge.com
HOME PAGE: Internet: http://www.gedigitalenergy.com/multilin
*1601-0071-EC*
Instruction Manual
489 Firmware Revision:
489PC Software Revision: 1.5X
Manual P/N: 1601-0071-EC
GE Publication code: GEK-106290D
GE Digital Energy's Quality
Management System is
registered to ISO9001:2000
QMI # 005094
© 2013 GE Multilin Inc. All rights reserved.
The 489 Generator Management Relay instruction manual for revision 1.5X.
489 Generator Management Relay is a registered trademark of GE Multilin Inc.
The contents of this manual are the property of GE Multilin Inc. This documentation is
furnished on license and may not be reproduced in whole or in part without the permission
of GE Multilin Inc. The content of this manual is for informational use only and is subject to
change without notice.
Part numbers contained in this manual are subject to change without notice, and should
therefore be verified by GE Multilin Inc. before ordering.
Part number: 1601-0071-EC (July 2013)
TABLE OF CONTENTS
1. INTRODUCTION
1.1 OVERVIEW
1.1.1
1.1.2
1.1.3
Description ......................................................................................................... 1-1
Ordering ............................................................................................................. 1-3
Other Accessories.............................................................................................. 1-3
1.2 SPECIFICATIONS
1.2.1
2. INSTALLATION
489 Specifications .............................................................................................. 1-4
2.1 MECHANICAL
2.1.1
2.1.2
2.1.3
2.1.4
2.1.5
Description ......................................................................................................... 2-1
Product Identification.......................................................................................... 2-2
Installation .......................................................................................................... 2-3
Unit Withdrawal and Insertion ............................................................................ 2-3
Terminal Locations............................................................................................. 2-5
2.2 ELECTRICAL
2.2.1
2.2.2
2.2.3
2.2.4
2.2.5
2.2.6
2.2.7
2.2.8
2.2.9
2.2.10
2.2.11
2.2.12
2.2.13
3. USER INTERFACES
Typical Wiring Diagram ...................................................................................... 2-7
General Wiring Considerations .......................................................................... 2-8
Control Power .................................................................................................... 2-9
Current Inputs .................................................................................................... 2-9
Voltage Inputs .................................................................................................. 2-11
Digital Inputs .................................................................................................... 2-11
Analog Inputs ................................................................................................... 2-11
Analog Outputs ................................................................................................ 2-12
RTD Sensor Connections ................................................................................ 2-12
Output Relays .................................................................................................. 2-13
IRIG-B .............................................................................................................. 2-13
RS485 Communications Ports ......................................................................... 2-14
Dielectric Strength............................................................................................ 2-15
3.1 FACEPLATE INTERFACE
3.1.1
3.1.2
3.1.3
3.1.4
Display ............................................................................................................... 3-1
LED Indicators.................................................................................................... 3-1
RS232 Program Port.......................................................................................... 3-2
Keypad ............................................................................................................... 3-2
3.2 SOFTWARE INTERFACE
3.2.1
3.2.2
3.2.3
3.2.4
3.2.5
3.2.6
3.2.7
3.2.8
3.2.9
4. SETPOINTS
Requirements..................................................................................................... 3-4
Installation/Upgrade ........................................................................................... 3-5
Configuration...................................................................................................... 3-7
Using 489PC ...................................................................................................... 3-8
Trending ........................................................................................................... 3-12
Waveform Capture ........................................................................................... 3-14
Phasors ............................................................................................................ 3-15
Event Recorder ................................................................................................ 3-16
Troubleshooting ............................................................................................... 3-17
4.1 OVERVIEW
4.1.1
4.1.2
4.1.3
4.1.4
4.1.5
Setpoint Message Map ...................................................................................... 4-1
Trips / Alarms/ Control Features ........................................................................ 4-5
Relay Assignment Practices .............................................................................. 4-5
Dual Setpoints.................................................................................................... 4-6
Commissioning................................................................................................... 4-6
4.2 S1 489 SETUP
4.2.1
4.2.2
4.2.3
4.2.4
4.2.5
GE Multilin
Passcode ........................................................................................................... 4-7
Preferences........................................................................................................ 4-7
Serial Ports......................................................................................................... 4-8
Real Time Clock................................................................................................. 4-9
Default Messages .............................................................................................. 4-9
489 Generator Management Relay
1
TABLE OF CONTENTS
4.2.6
4.2.7
Message Scratchpad ........................................................................................4-10
Clear Data.........................................................................................................4-11
4.3 S2 SYSTEM SETUP
4.3.1
4.3.2
4.3.3
4.3.4
Current Sensing................................................................................................4-12
Voltage Sensing................................................................................................4-12
Generator Parameters ......................................................................................4-13
Serial Start/Stop Initiation .................................................................................4-13
4.4 S3 DIGITAL INPUTS
4.4.1
4.4.2
4.4.3
4.4.4
4.4.5
4.4.6
4.4.7
4.4.8
4.4.9
4.4.10
4.4.11
4.4.12
Description ........................................................................................................4-14
Breaker Status ..................................................................................................4-14
General Input A to G .........................................................................................4-15
Remote Reset ...................................................................................................4-16
Test Input..........................................................................................................4-16
Thermal Reset ..................................................................................................4-16
Dual Setpoints ..................................................................................................4-16
Sequential Trip..................................................................................................4-17
Field-Breaker Discrepancy ...............................................................................4-18
Tachometer.......................................................................................................4-18
Waveform Capture............................................................................................4-19
Ground Switch Status .......................................................................................4-19
4.5 S4 OUTPUT RELAYS
4.5.1
4.5.2
Description ........................................................................................................4-20
Relay Reset Mode ............................................................................................4-20
4.6 S5 CURRENT ELEMENTS
4.6.1
4.6.2
4.6.3
4.6.4
4.6.5
4.6.6
4.6.7
4.6.8
4.6.9
4.6.10
inverse Time Overcurrent Curve Characteristics ..............................................4-21
Overcurrent Alarm ............................................................................................4-24
Offline Overcurrent ...........................................................................................4-24
Inadvertent Energization ...................................................................................4-25
Voltage Restrained Phase Overcurrent ............................................................4-26
Negative Sequence Overcurrent ......................................................................4-27
Ground Overcurrent ..........................................................................................4-29
Phase Differential .............................................................................................4-30
Ground Directional ............................................................................................4-31
High-Set Phase Overcurrent.............................................................................4-32
4.7 S6 VOLTAGE ELEMENTS
4.7.1
4.7.2
4.7.3
4.7.4
4.7.5
4.7.6
4.7.7
4.7.8
4.7.9
4.7.10
Undervoltage ....................................................................................................4-33
Overvoltage ......................................................................................................4-34
Volts/Hertz ........................................................................................................4-35
Phase Reversal ................................................................................................4-36
Underfrequency ................................................................................................4-37
Overfrequency ..................................................................................................4-38
Neutral Overvoltage (Fundamental) .................................................................4-39
Neutral Overvoltage (3rd Harmonic) .................................................................4-40
Loss of Excitation..............................................................................................4-42
Distance Element..............................................................................................4-43
4.8 S7 POWER ELEMENTS
4.8.1
4.8.2
4.8.3
4.8.4
Power Measurement Conventions....................................................................4-45
Reactive Power.................................................................................................4-46
Reverse Power .................................................................................................4-47
Low Forward Power ..........................................................................................4-48
4.9 S8 RTD TEMPERATURE
4.9.1
4.9.2
4.9.3
4.9.4
4.9.5
4.9.6
4.9.7
RTD Types........................................................................................................4-49
RTDs 1 to 6.......................................................................................................4-50
RTDs 7 to 10.....................................................................................................4-51
RTD 11 .............................................................................................................4-52
RTD 12 .............................................................................................................4-53
Open RTD Sensor ............................................................................................4-54
RTD Short/Low Temperature............................................................................4-54
4.10 S9 THERMAL MODEL
4.10.1
4.10.2
4.10.3
2
489 Thermal Model ...........................................................................................4-55
Model Setup......................................................................................................4-56
Thermal Elements.............................................................................................4-68
489 Generator Management Relay
GE Multilin
TABLE OF CONTENTS
4.11 S10 MONITORING
4.11.1
4.11.2
4.11.3
4.11.4
4.11.5
4.11.6
4.11.7
Trip Counter ..................................................................................................... 4-69
Breaker Failure................................................................................................. 4-69
Trip Coil Monitor............................................................................................... 4-70
VT Fuse Failure................................................................................................ 4-71
Current, MW, Mvar, and MVA Demand ........................................................... 4-72
Pulse Output .................................................................................................... 4-74
Generator Running Hour Setup ....................................................................... 4-74
4.12 S11 ANALOG I/O
4.12.1
4.12.2
Analog Outputs 1 to 4 ...................................................................................... 4-75
Analog Inputs 1 to 4 ......................................................................................... 4-76
4.13 S12 TESTING
4.13.1
4.13.2
4.13.3
4.13.4
4.13.5
4.13.6
4.13.7
5. ACTUAL VALUES
Simulation Mode .............................................................................................. 4-78
Pre-Fault Setup ................................................................................................ 4-79
Fault Setup....................................................................................................... 4-80
Test Output Relays .......................................................................................... 4-81
Test Analog Output .......................................................................................... 4-81
Comm Port Monitor .......................................................................................... 4-82
Factory Service ................................................................................................ 4-82
5.1 OVERVIEW
5.1.1
Actual Values Messages.................................................................................... 5-1
5.2 A1 STATUS
5.2.1
5.2.2
5.2.3
5.2.4
5.2.5
5.2.6
5.2.7
Generator Status................................................................................................ 5-3
Last Trip Data..................................................................................................... 5-3
Alarm Status....................................................................................................... 5-4
Trip Pickups ....................................................................................................... 5-6
Alarm Pickups .................................................................................................... 5-9
Digital Inputs .................................................................................................... 5-12
Real Time Clock............................................................................................... 5-12
5.3 A2 METERING DATA
5.3.1
5.3.2
5.3.3
5.3.4
5.3.5
5.3.6
5.3.7
Current Metering .............................................................................................. 5-13
Voltage Metering .............................................................................................. 5-14
Power Metering ................................................................................................ 5-15
Temperature..................................................................................................... 5-16
Demand Metering............................................................................................. 5-17
Analog Inputs ................................................................................................... 5-17
Speed............................................................................................................... 5-17
5.4 A3 LEARNED DATA
5.4.1
5.4.2
5.4.3
Parameter Averages ........................................................................................ 5-18
RTD Maximums ............................................................................................... 5-18
Analog Input Minimum/Maximum..................................................................... 5-19
5.5 A4 MAINTENANCE
5.5.1
5.5.2
5.5.3
Trip Counters ................................................................................................... 5-20
General Counters............................................................................................. 5-22
Timers .............................................................................................................. 5-22
5.6 A5 EVENT RECORDER
5.6.1
Event Recorder ................................................................................................ 5-23
5.7 A6 PRODUCT INFO
5.7.1
5.7.2
489 Model Info ................................................................................................. 5-25
Calibration Info ................................................................................................. 5-25
5.8 DIAGNOSTICS
5.8.1
5.8.2
6. COMMUNICATIONS
6.1 MODBUS PROTOCOL
6.1.1
GE Multilin
Diagnostic Messages ....................................................................................... 5-26
Flash Messages ............................................................................................... 5-27
Electrical Interface.............................................................................................. 6-1
489 Generator Management Relay
3
TABLE OF CONTENTS
6.1.2
6.1.3
6.1.4
6.1.5
6.1.6
Modbus RTU Description....................................................................................6-1
Data Frame Format and Data Rate ....................................................................6-1
Data Packet Format ............................................................................................6-1
CRC-16 Algorithm...............................................................................................6-2
Timing .................................................................................................................6-2
6.2 MODBUS FUNCTIONS
6.2.1
6.2.2
6.2.3
6.2.4
6.2.5
6.2.6
6.2.7
6.2.8
6.2.9
Supported Functions...........................................................................................6-3
Function Codes 03/04: Read Setpoints / Actual Values .....................................6-3
Function Code 05: Execute Operation................................................................6-4
Function Code 06: Store Single Setpoint............................................................6-4
Function Code 07: Read Device Status..............................................................6-5
Function Code 08: Loopback Test ......................................................................6-5
Function Code 16: Store Multiple Setpoints .......................................................6-6
Function Code 16: Performing Commands ........................................................6-7
Error Responses .................................................................................................6-7
6.3 MODBUS MEMORY MAP
6.3.1
6.3.2
6.3.3
6.3.4
6.3.5
6.3.6
6.3.7
6.3.8
Memory Map Information ....................................................................................6-8
User-Definable Memory Map Area .....................................................................6-8
Event Recorder ...................................................................................................6-8
Waveform Capture..............................................................................................6-9
Dual Setpoints ....................................................................................................6-9
Passcode Operation ...........................................................................................6-9
489 Memory Map ..............................................................................................6-10
Memory Map Data Formats ..............................................................................6-34
6.4 DNP PROTOCOL
6.4.1
6.4.2
6.4.3
Device Profile Document ..................................................................................6-39
Implementation Table .......................................................................................6-41
Default Variations .............................................................................................6-42
6.5 DNP POINT LISTS
6.5.1
6.5.2
6.5.3
6.5.4
7. TESTING
Binary Input / Binary Input Change (Objects 01/02) .........................................6-43
Binary / Control Relay Output Block (Objects 10/12)........................................6-45
Binary / Frozen Counter (Objects 20/21) ..........................................................6-46
Analog Input / Input Change (Objects 30/32) ...................................................6-47
7.1 TEST SETUP
7.1.1
7.1.2
Description ..........................................................................................................7-1
Secondary Current Injection Test Setup .............................................................7-2
7.2 HARDWARE FUNCTIONAL TESTS
7.2.1
7.2.2
7.2.3
7.2.4
7.2.5
7.2.6
7.2.7
7.2.8
7.2.9
Output Current Accuracy ....................................................................................7-3
Phase Voltage Input Accuracy............................................................................7-3
Ground (1 A), Neutral, and Differential Current Accuracy...................................7-4
Neutral Voltage (Fundamental) Accuracy ...........................................................7-4
Negative Sequence Current Accuracy................................................................7-5
RTD Accuracy.....................................................................................................7-6
Digital Inputs and Trip Coil Supervision ..............................................................7-7
Analog Inputs and Outputs .................................................................................7-7
Output Relays .....................................................................................................7-8
7.3 ADDITIONAL FUNCTIONAL TESTS
7.3.1
7.3.2
7.3.3
7.3.4
7.3.5
7.3.6
7.3.7
7.3.8
7.3.9
7.3.10
4
Overload Curve Accuracy ...................................................................................7-9
Power Measurement Test.................................................................................7-10
Reactive Power Accuracy .................................................................................7-11
Voltage Phase Reversal Accuracy ...................................................................7-12
Injection Test Setup #2 .....................................................................................7-12
GE Multilin HGF Ground Accuracy ...................................................................7-13
Neutral Voltage (3rd Harmonic) Accuracy ........................................................7-13
Phase Differential Trip Accuracy ......................................................................7-14
Injection Test Setup #3 .....................................................................................7-15
Voltage Restrained Overcurrent Accuracy .......................................................7-16
489 Generator Management Relay
GE Multilin
TABLE OF CONTENTS
A. APPLICATION NOTES
A.1 STATOR GROUND FAULT
A.1.1
A.1.2
A.1.3
A.1.4
A.1.5
A.1.6
Description .........................................................................................................A-1
Neutral Overvoltage Element .............................................................................A-1
Ground Overcurrent Element .............................................................................A-2
Ground Directional Element ...............................................................................A-3
Third Harmonic Voltage Element .......................................................................A-5
References.........................................................................................................A-5
A.2 CURRENT TRANSFORMERS
A.2.1
A.2.2
A.2.3
B. CURVES
B.1 TIME OVERCURRENT CURVES
B.1.1
B.1.2
B.1.3
B.1.4
C. MISCELLANEOUS
Ground Fault CTs for 50:0.025 A CT .................................................................A-6
Ground Fault CTs for 5 A Secondary CT ...........................................................A-7
Phase CTs .........................................................................................................A-8
ANSI Curves ......................................................................................................B-1
Definite Time Curves..........................................................................................B-5
IAC Curves.........................................................................................................B-6
IEC Curves.......................................................................................................B-10
C.1 REVISION HISTORY
C.1.1
C.1.2
Change Notes ....................................................................................................C-1
Changes Since Last Revision ............................................................................C-1
C.2 EU DECLARATION OF CONFORMITY
C.2.1
EU declaration of conformity .............................................................................C-2
C.3 WARRANTY INFORMATION
C.3.1
GE Multilin
GE Multilin Warranty ..........................................................................................C-3
489 Generator Management Relay
5
TABLE OF CONTENTS
6
489 Generator Management Relay
GE Multilin
1 INTRODUCTION
1.1 OVERVIEW
1 INTRODUCTION 1.1OVERVIEW
1.1.1 DESCRIPTION
The 489 Generator Management Relay is a microprocessor-based relay designed for the protection and management of
synchronous and induction generators. The 489 is equipped with 6 output relays for trips and alarms. Generator protection,
fault diagnostics, power metering, and RTU functions are integrated into one economical drawout package. The single line
diagram below illustrates the 489 functionality using ANSI (American National Standards Institute) device numbers.
Synch
ronou
s
Induc
tion
489
12
21
24
27
50/27
32
38
39
40
40Q
46
47
49
50
50BF
50
50/51GN
51V
59
59GN/27TN
60FL
67
76
81
86
87G
52
overspeed
distance
volts/hertz
undervoltage
inadvertent generator energization
reverse power/low forward power
bearing overtemperature (RTD)
bearing vibration (analog inputs)
loss of excitation (impedance)
loss of field (reactive power)
2
negative sequence overcurrent (I 2 t)
voltage phase reversal
stator thermal (RTD/thermal model)
high-set phase overcurrent
breaker failure detection
offline overcurrent
ground overcurrent
voltage restrained phase overcurrent
overvoltage
100% stator ground
VT fuse failure
ground directional
Trip Coil
Supervision
27
47
59
810
40
81U
24
21
38
41
GENERATOR
12
49
39
32
40Q
50/27
51V
60FL
76
46
Output
relays
49
86
Output
relays
6
50BF
50
87G
RS232
RS485
67 50/51GN RS485
overexcitation (analog input)
overfrequency/underfrequency
electrical lockout
percentage differential
sequential tripping logic
trip coil supervision
generator running hours alarm
59GN
27TN
+
+
-
4
4
Analog
outputs
Analog
inputs
808783E8.CDR
Figure 1–1: SINGLE LINE DIAGRAM
Fault diagnostics are provided through pretrip data, event record, waveform capture, and statistics. Prior to issuing a trip,
the 489 takes a snapshot of the measured parameters and stores them in a record with the cause of the trip. This pre-trip
data may be viewed using the NEXT key before the trip is reset, or by accessing the last trip data in actual values page 1.
The event recorder stores a maximum of 40 time and date stamped events including the pre-trip data. Every time a trip
occurs, the 489 stores a 16 cycle trace for all measured AC quantities. Trip counters record the number of occurrences of
each type of trip. Minimum and maximum values for RTDs and analog inputs are also recorded. These features allow the
operator to pinpoint a problem quickly and with certainty.
A complete list protection features may be found below in the table below:
GE Multilin
489 Generator Management Relay
1-1
1
1.1 OVERVIEW
1
1 INTRODUCTION
Table 1–1: TRIP AND ALARM PROTECTION FEATURES
TRIP PROTECTION
ALARM PROTECTION
Seven (7) Assignable Digital Inputs: General Input,
Sequential Trip (low forward power or reverse power), FieldBreaker discrepancy, and Tachometer
7 assignable digital inputs: general input and tachometer
Overload
Negative Sequence
Offline Overcurrent (protection during startup)
Ground Overcurrent
Inadvertent Energization
Ground Directional
Phase Overcurrent with Voltage Restraint
Undervoltage
Negative-Sequence Overcurrent
Overvoltage
Ground Overcurrent
Volts Per Hertz
Percentage Phase Differential
Underfrequency
Ground Directional
Overfrequency
High-Set Phase Overcurrent
Neutral Overvoltage (Fundamental)
Undervoltage
Neutral Undervoltage (3rd Harmonic)
Overvoltage
Reactive Power (kvar)
Volts Per Hertz
Reverse Power
Voltage Phase Reversal
Low Forward Power
Underfrequency (two step)
RTD: Stator, Bearing, Ambient, Other
Overfrequency (two step)
Short/Low RTD
Neutral Overvoltage (Fundamental)
Open RTD
Neutral Undervoltage (3rd Harmonic)
Thermal Overload
Loss of Excitation (2 impedance circles)
Trip Counter
Distance Element (2 zones of protection)
Breaker Failure
Reactive Power (kvar) for loss of field
Trip Coil Monitor
Reverse Power for anti-motoring
VT Fuse Failure
Low Forward Power
Demand: Current, MW, Mvar, MVA
RTDs: Stator, Bearing, Ambient, Other
Generator Running Hours
Thermal Overload
Analog Inputs 1 to 4
Analog Inputs 1 to 4
Service (Self-Test Failure)
Electrical Lockout
IRIG-B Failure
Power metering is a standard feature in the 489. The table below outlines the metered parameters available to the operator
or plant engineer either through the front panel or communications ports. The 489 is equipped with three fully functional and
independent communications ports. The front panel RS232 port may be used for setpoint programming, local interrogation
or control, and firmware upgrades. The computer RS485 port may be connected to a PLC, DCS, or PC based interface
software. The auxiliary RS485 port may be used for redundancy or simultaneous interrogation and/or control from a second
PLC, DCS, or PC program. There are also four 4 to 20 mA transducer outputs that may be assigned to any measured
parameter. The range of these outputs is scalable. Additional features are outlined below.
Table 1–2: METERING AND ADDITIONAL FEATURES
METERING
ADDITIONAL FEATURES
Voltage (phasors)
Drawout Case (for ease of maintenance and testing)
Current (phasors) and Amps Demand
Breaker Failure
Real Power, MW Demand, MWh
Trip Coil Supervision
Apparent Power and MVA Demand
VT Fuse Failure
Reactive Power, Mvar Demand, Positive and Negative MVarh
Simulation
Frequency
Flash Memory for easy firmware upgrades
Power Factor
RTD
Speed in RPM with a Key Phasor Input
User-Programmable Analog Inputs
1-2
489 Generator Management Relay
GE Multilin
1 INTRODUCTION
1.1 OVERVIEW
1.1.2 ORDERING
All features of the 489 are standard, there are no options. The phase CT secondaries must be specified at the time of order.
The control power and analog output range must also be specified at the time of order. There are two ground CT inputs:
one for the GE Multilin HGF core balance CT and one for a ground CT with a 1 A secondary (may also be used to accommodate 5 A secondary). The VT inputs accommodate VTs in either a delta or wye configuration. The output relays are
always non-failsafe with the exception of the service relay. The 489PC software is provided with each unit. A metal demo
case may be ordered for demonstration or testing purposes.
Table 1–3: 489 ORDER CODES
489 —

—

—

|
|
|
489 Generator Management Relay Base Unit
P1
|
|
Current Transformer Inputs: 1 A CT Secondaries
Current Transformer Inputs: 5 A CT Secondaries
489
|
|
LO
|
20 to 60 V DC; 20 to 48 V AC at 48 to 62 Hz
HI
|
88 to 300 V DC; 70 to 265 V AC at 48 to 62 Hz
P5
A1
0 to 1 mA Analog Outputs
A20
4 to 20 mA Analog Outputs
For example, the 489-P1-LO-A20 code specifies a 489 Generator Management Relay with 1 A CT Inputs, 20 to 60 V DC or
20 to 48 V AC control voltage, and 4 to 20 mA Analog Outputs.
1.1.3 OTHER ACCESSORIES
Additional 489 accessories are listed below.
•
489PC software:
Shipped free with 489
•
DEMO:
Metal carry case in which 489 unit may be mounted
•
SR 19-1 PANEL:
Single cutout for 19” panel
•
SR 19-2 PANEL:
Double cutout for 19” panel
•
SCI MODULE:
RS232 to RS485 converter box, designed for harsh industrial environments
•
Phase CT:
50, 75, 100, 150, 200, 250, 300, 350, 400, 500, 600, 750, 1000 phase CT primaries
•
HGF3, HGF5, HGF8:
For sensitive ground detection on high resistance grounded systems
•
489 1 3/8” Collar:
For shallow switchgear, reduces the depth of the relay by 1 3/8”
•
489 3” Collar:
For shallow switchgear, reduces the depth of the relay by 3”
GE Multilin
489 Generator Management Relay
1-3
1
1.2 SPECIFICATIONS
1 INTRODUCTION
1.2SPECIFICATIONS
1
1.2.1 489 SPECIFICATIONS
PHASE VOLTAGE INPUTS
POWER SUPPLY
Options:
LO / HI
(must be specified when ordering)
VT Ratio:
1.00 to 240.00:1 in steps of 0.01
VT Secondary:
200 V AC (full-scale)
DC: 20 to 60 V DC
AC: 20 to 48 V AC at 48 to 62 Hz
Conversion Range:
0.02 to 1.00 × Full Scale
HI Range:
DC: 90 to 300 V DC
AC: 70 to 265 V AC at 48 to 62 Hz
Accuracy:
±0.5% of Full Scale
Max. Continuous:
280 V AC
Power:
45 VA (max), 25 VA typical
Burden:
> 500 KΩ
LO Range:
Proper operation time without supply voltage: 30 ms
AC ANALOG INPUTS FREQUENCY TRACKING
Frequency Tracking:
Va for wye, Vab for open delta
6 V minimum, 10 Hz/sec.
OUTPUT AND NEUTRAL END CURRENT INPUTS
CT Primary:
NEUTRAL VOLTAGE INPUT
VT Ratio:
1.00 to 240.00:1 in steps of 0.01
VT Secondary:
100 V AC (full-scale)
Conversion Range:
0.005 to 1.00 × Full Scale
Accuracy:
Fundamental:+/-0.5% of Full Scale
3rd Harmonic at >3V secondary: +/-5%
of reading
10 to 50000 A
CT Secondary:
1 A or 5 A (must be specified with order)
Conversion Range:
0.02 to 20 × CT
Accuracy:
at < 2 × CT: ±0.5% of 2 × CT
at ≥ 2 × CT: ±1% of 20 × CT
Burden:
Less than 0.2 VA at rated load
CT Withstand:
1 second at 80 times rated current
2 seconds at 40 times rated current
continuous at 3 times rated current
3rd Harmonic at < 3V secondary: +/0.15% of full scale
Max. Continuous:
Inputs:
9 opto-isolated inputs
External Switch:
dry contact < 400 Ω, or open collector
NPN transistor from sensor
6 mA sinking from internal 4K pullup at
24 V DC with Vce < 4 V DC
GROUND CURRENT INPUT
CT Primary:
10 to 10000 A (1 A / 5 A CTs)
CT Secondary:
1 A / 5 A or 50:0.025 (HGF CTs)
Conversion Range:
0.02 to 20 × CT for 1 A / 5 A CTs
0.0 to 100 A pri. for 50:0.025 CTs (HGF)
50:0.025 CT Accuracy:
± 0.1 A at < 10 A
± 1.0 A at ≥ 10 to 100 A
1 A / 5 A CT Accuracy:
at < 2 × CT: ±0.5% of 2 × CT
at ≥ 2 × CT: ±1% of 20 × CT
GROUND CT BURDEN
GROUND
CT
1A/5A
50:0.025
HGF
INPUT
BURDEN
RTD INPUTS
RTDs (3 wire type):
100 Ω Platinum (DIN.43760)
100 Ω Nickel, 120 Ω Nickel,
10 Ω Copper
RTD Sensing Current:
5 mA
Isolation:
36 Vpk
(isolated with analog inputs and outputs)
Range:
–50 to +250°C
Accuracy:
±2°C for Platinum and Nickel
±5°C for Copper
1A
0.024
0.024
Lead Resistance:
25 Ω Max per lead
0.605
0.024
No Sensor:
>1 kΩ
20 A
9.809
0.024
Short/Low Alarm:
< –50°C
0.025 A
0.057
90.7
TRIP COIL SUPERVISION
0.1 A
0.634
90.7
Applicable Voltage:
20 to 300 V DC/AC
Trickle Current:
2 to 5 mA
18.9
75.6
GROUND CT CURRENT WITHSTAND (SECONDARY)
GROUND CT
ANALOG CURRENT INPUTS
Current Inputs:
WITHSTAND TIME
1 SEC.
50:0.025 HGF
24 V DC at 20 mA max.
5A
0.5 A
1A/5A
489 Sensor Supply:
Ω
VA
280 V AC
DIGITAL INPUTS
2 SEC.
CONTINUOUS
80 × CT
40 × CT
3 × CT
N/A
N/A
150 mA
0 to 1 mA, 0 to 20 mA, 4 to 20mA
(setpoint)
Input Impedance:
226 Ω ±10%
Conversion Range:
0 to 2 mA
Accuracy:
±1% of full scale
Type:
Passive
Analog Input Supply:
+24 V DC at 100 mA max.
Sampling Interval:
50 ms
COMMUNICATIONS PORTS
1-4
RS232 Port:
1, Front Panel, non-isolated
RS485 Ports:
2, Isolated together at 36 Vpk
489 Generator Management Relay
GE Multilin
1 INTRODUCTION
1.2 SPECIFICATIONS
RS485 Baud Rates:
300, 1200, 2400, 4800, 9600, 19200
RS232 Baud Rate:
9600
Parity:
None, Odd, Even
®
Modbus RTU / half duplex, DNP 3.0
Protocol:
ANALOG CURRENT OUTPUT
VOLTAGE
AC
120 V
INDUCTIVE
250 V
PF = 0.4
MAKE/CARRY
BREAK
MAX.
LOAD
30 A
4A
480 VA
30 A
3A
750 VA
CTS
0.2 s
10 A
10 A
Type:
Active
TERMINALS
Range:
4 to 20mA, 0 to 1 mA
(must be specified with order)
Low Voltage (A, B, C, D terminals): 12 AWG max
Accuracy:
±1% of full scale
4 to 20 mA max. load:
1.2 kΩ
0 to 1mA max. load:
10 kΩ
Isolation:
36 Vpk
(isolated with RTDs and analog inputs)
4 Assignable Outputs:
Phase A, B, C output current
3 phase average current
negative sequence current
generator load
hottest stator RTD
hottest bearing RTD
RTD # 1 to 12
AB voltage
BC voltage
CA voltage
average phase-phase voltage
volts/hertz
frequency
3rd harmonic neutral voltage
power factor
3 phase reactive power (Mvar)
3 phase real power (MW)
3 phase apparent power (MVA)
analog inputs 1 to 4
tachometer
thermal capacity used
I, Mvar, MW, MVA demands
Torque
High Voltage (E, F, G, H terminals): #8 ring lug,
10 AWG wire standard
POWER METERING
6 electromechanical Form C relays
silver alloy
Operate Time:
10 ms
Max Ratings for 100000 operations:
0.2 s
Range:
0.000 to 4000000.000 MvarHours
Timing Accuracy:
±0.5%
Update Rate:
50 ms
Metered Values:
Maximum Phase Current
3 Phase Real Power
3 Phase Apparent Power
3 Phase Reactive Power
Measurement Type:
Rolling Demand
Demand Interval:
5 to 90 minutes in steps of 1
Update Rate:
1 minute
Elements:
Alarm
GENERAL INPUT A TO G (DIGITAL INPUT)
Contact Material:
MAKE/CARRY
Continuous total of +watthours and
±varhours
DEMAND METERING
Configuration:
CTS
±1% of 3 × 2 × CT × VT × VT full-scale
±1.5% of 3 × 20 × CT × VT × VT full-scl.
Description:
Relay contacts must be considered unsafe to touch
when the 489 is energized! If the output relay contacts are required for low voltage accessible applications, it is the customer's responsibility to ensure
proper insulation levels.
VOLTAGE
0.000 to 2000.000 ±Mw, ±Mvar, MVA
Accuracy
at Iavg < 2 × CT:
at Iavg > 2 × CT:
WATTHOUR AND VARHOUR METERING
OUTPUT RELAYS
WARNING
Range:
BREAK
MAX.
LOAD
Configurable:
Assignable Digital Inputs 1 to 7
Time Delay:
0.1 to 2100.0 s in steps of 0.1
Block From Online:
0 to 5000 s in steps of 1
Timing Accuracy:
±100 ms or ±0.5% of total time
Elements:
Trip, Alarm, and Control
SEQUENTIAL TRIP (DIGITAL INPUT)
Configurable:
Assignable to Digital Inputs 1 to 7
Pickup Level:
0.02 to 0.99 × rated MW in steps of 0.01
Low Forward Power / Reverse Power
Time Delay:
0.2 to 120.0 s in steps of 0.1
Pickup Accuracy:
see power metering
Timing Accuracy:
±100 ms or ±0.5% of total time
Elements:
Trip
FIELD BREAKER DISCREPANCY (DIGITAL INPUT)
Configurable:
Assignable to Digital Inputs 1 to 7
Time Delay:
0.1 to 500.0 s in steps of 0.1
DC
30 V
RESISTIVE
125 V
10 A
30 A
10 A
300 W
10 A
30 A
0.5 A
62.5 W
250 V
10 A
30 A
0.3 A
75 W
30 V
DC
INDUCTIVE
L/R = 40 ms 125 V
250 V
10 A
30 A
5A
150 W
10 A
30 A
0.25 A
31.3 W
Configurable:
Assignable to Digital Inputs 4 to 7
10 A
30 A
0.15 A
37.5 W
RPM Measurement:
100 to 7200 RPM
10 A
30 A
10 A
2770 VA
Duty Cycle of Pulse:
>10%
10 A
30 A
10 A
2770 VA
Pickup Level:
101 to 175 × rated speed in steps of 1
Time Delay:
1 to 250 s in steps of 1
AC
120 V
RESISTIVE
250 V
GE Multilin
Timing Accuracy:
±100 ms or ±0.5% of total time
Elements:
Trip
TACHOMETER (DIGITAL INPUT)
489 Generator Management Relay
1-5
1
1.2 SPECIFICATIONS
1
1 INTRODUCTION
Timing Accuracy:
±0.5 s or ±0.5% of total time
PHASE DIFFERENTIAL
Elements:
Trip and Alarm
Pick-up Level:
OVERCURRENT ALARM
0.05 to 1.00 × CT in steps of 0.01
Curve Shape:
Dual Slope
Pick-up Level:
0.10 to 1.50 × FLA in steps of 0.01
average phase current
Time Delay:
0 to 100 cycles in steps of 1
Pickup Accuracy:
as per Phase Current Inputs
Time Delay:
0.1 to 250.0 s in steps of 0.1
Timing Accuracy:
+50 ms at 50/60 Hz or ±0.5% total time
Pickup Accuracy:
as per Phase Current Inputs
Elements:
Trip
Timing Accuracy:
±100 ms or ±0.5% of total time
GROUND DIRECTIONAL
Elements:
Alarm
Pickup Level:
OFFLINE OVERCURRENT
0.05 to 20.00 × CT in steps of 0.01
Time Delay:
0.1 to 120.0 s in steps of 0.1
as per Phase Current Inputs
Pick-up Level:
0.05 to 1.00 × CT in steps of 0.01
of any one phase
Pickup Accuracy:
Timing Accuracy:
±100 ms or ±0.5% of total time
Time Delay:
3 to 99 cycles in steps of 1
Elements:
Trip and Alarm
Pickup Accuracy:
as per Phase Current Inputs
Timing Accuracy:
+50ms at 50/60 Hz
HIGH-SET PHASE OVERCURRENT
Elements:
Trip
Pickup Level:
0.15 to 20.00 × CT in steps of 0.01
Time Delay:
0.00 to 100.00 s in steps of 0.01
INADVERTENT ENERGIZATION
Pickup Accuracy:
as per Phase Current Inputs
Arming Signal:
undervoltage and/or offline from breaker
status
Timing Accuracy:
±50 ms at 50/60 Hz or ±0.5% total time
Trip
Pick-up Level:
0.05 to 3.00 × CT in steps of 0.01
of any one phase
Elements:
UNDERVOLTAGE
Time Delay:
no intentional delay
Pickup Accuracy:
as per Phase Current Inputs
Timing Accuracy:
+50 ms at 50/60 Hz
Elements:
Trip
PHASE OVERCURRENT
Pick-up Level:
0.50 to 0.99 × rated V in steps of 0.01
Curve Shapes:
Inverse Time, definite time alarm
Time Delay:
0.2 to 120.0 s in steps of 0.1
Pickup Accuracy:
as per Voltage Inputs
Timing Accuracy:
±100 ms or ±0.5% of total time
Elements:
Trip and Alarm
Voltage Restraint:
Programmable fixed characteristic
Pick-up Level:
0.15 to 20.00 × CT in steps of 0.01
of any one phase
OVERVOLTAGE
Pick-up Level:
1.01 to 1.50 × rated V in steps of 0.01
Curve Shapes:
ANSI, IEC, IAC, Flexcurve, Definite Time
Curve Shapes:
Inverse Time, definite time alarm
Time Delay:
0.000 to 100.000 s in steps of 0.001
Time Delay:
0.2 to 120.0 s in steps of 0.1
Pickup Accuracy:
as per Phase Current Inputs
Pickup Accuracy:
as per Voltage Inputs
Timing Accuracy:
+50 ms at 50/60 Hz or ±0.5% total time
Timing Accuracy:
±100 ms or ±0.5% of total time
Elements:
Trip
Elements:
Trip and Alarm
VOLTS/HERTZ
NEGATIVE SEQUENCE OVERCURRENT
Pick-up Level:
1.00 to 1.99 × nominal in steps of 0.01
Curve Shapes:
Inverse Time, definite time alarm
0.1 to 100.0 s in steps of 0.1
Time Delay:
0.1 to 120.0 s in steps of 0.1
as per Phase Current Inputs
Pickup Accuracy:
as per voltage inputs
Timing Accuracy:
±100ms or ± 0.5% of total time
Timing Accuracy:
Elements:
Trip and Alarm
±100 ms at ≥ 1.2 × Pickup
±300 ms at < 1.2 × Pickup
Elements:
Trip and Alarm
Pick-up Level:
Curve Shapes:
Time Delay:
Pickup Accuracy:
3 to 100% FLA in steps of 1
I2
2t
trip defined by k, definite time alarm
GROUND OVERCURRENT
Pick-up Level:
0.05 to 20.00 × CT in steps of 0.01
Curve Shapes:
ANSI, IEC, IAC, Flexcurve, Definite Time
Time Delay:
0.00 to 100.00 s in steps of 0.01
Pickup Accuracy:
as per Ground Current Input
VOLTAGE PHASE REVERSAL
Configuration:
ABC or ACB phase rotation
Timing Accuracy:
200 to 400 ms
Elements:
Trip
Timing Accuracy:
+50 ms at 50/60 Hz or ±0.5% total time
UNDERFREQUENCY
Elements:
Trip
Required Voltage:
0.50 to 0.99 × rated voltage in Phase A
Block From Online:
0 to 5 sec. in steps of 1
1-6
Pick- up Level:
20.00 to 60.00 in steps of 0.01
Curve Shapes:
1 level alarm, two level trip definite time
Time Delay:
0.1 to 2100.0 sec. in steps of 0.1
Pickup Accuracy:
±0.02 Hz
Timing Accuracy:
±100 ms or ±0.5% of total time
489 Generator Management Relay
GE Multilin
1 INTRODUCTION
Elements:
1.2 SPECIFICATIONS
LOW FORWARD POWER
Trip and Alarm
OVERFREQUENCY
Required Voltage:
0.50 to 0.99 × rated voltage in Phase A
Block From Online:
0 to 15000 s in steps of 1
Pick- up Level:
0.02 to 0.99 × rated MW
Block From Online:
0 to 5 sec. in steps of 1
Time Delay:
0.2 to 120.0 s in steps of 0.1
Pick- up Level:
25.01 to 70.00 in steps of 0.01
Pickup Accuracy:
see power metering
Curve Shapes:
1 level alarm, 2 level trip definite time
Timing Accuracy:
±100 ms or ±0.5% of total time
Time Delay:
0.1 to 2100.0 s in steps of 0.1
Elements:
Trip and Alarm
Pickup Accuracy:
±0.02 Hz
PULSE OUTPUT
Timing Accuracy:
±100 ms or ±0.5% of total time
Parameters:
+ kwh, +kvarh, -kvarh
Elements:
Trip and Alarm
Interval:
1 to 50000 in steps of 1
NEUTRAL OVERVOLTAGE (FUNDAMENTAL)
Pulse Width:
200 to 1000 ms in steps of 1 ms
Pick-up Level:
2.0 to 100.0 V secondary in steps of 0.01
RTDS 1 TO 12
Time Delay:
0.1 to 120.0 s in steps of 0.1
Pickup:
1 to 250°C in steps of 1
Pickup Accuracy:
as per Neutral Voltage Input
Pickup Hysteresis:
2°C
Timing Accuracy:
±100 ms or ±0.5% of total time
Time Delay:
3 sec.
Elements:
Trip and Alarm
Elements:
Trip and Alarm
1
NEUTRAL UNDERVOLTAGE (3RD HARMONIC)
OVERLOAD / STALL PROTECTION / THERMAL MODEL
Blocking Signals:
Low power and low voltage if open delta
Overload Curves:
Pick-up Level:
0.5 to 20.0 V secondary in steps of 0.01
if open delta VT; adaptive if wye VT
Time Delay:
5 to 120 s in steps of 1
Pickup Accuracy:
Timing Accuracy:
as per Neutral Voltage Input
±3.0 s
15 Standard Overload Curves
Custom Curve
Voltage Dependent Custom Curve
(all curves time out against average
phase current)
Curve Biasing:
Elements:
Trip and Alarm
Phase Unbalance
Hot/Cold Curve Ratio
Stator RTD
Online Cooling Rate
Offline Cooling Rate
Line Voltage
LOSS OF EXCITATION (IMPEDANCE)
Pickup Level:
2.5 to 300.0 Ω secondary in steps of 0.1
with adjustable impedance offset 1.0 to
300.0 Ω secondary in steps of 0.1
Overload Pickup:
1.01 to 1.25
Time Delay:
0.1 to 10.0 s in steps of 0.1
Pickup Accuracy:
as per Phase Current Inputs
Pickup Accuracy:
as per Voltage and Phase Current Inputs
Timing Accuracy:
±100 ms or ±2% of total time
Timing Accuracy:
±100 ms or ±0.5% of total time
Elements:
Trip and Alarm
Elements:
Trip (2 zones using impedance circles)
OTHER FEATURES
Serial Start/Stop Initiation
DISTANCE (IMPEDANCE)
Pickup Levels:
0.1 to 500.0 Ω secondary in steps of 0.1
50 to 85° reach in steps of 1
Remote Reset (Configurable Digital Input)
Time Delay:
0.0 to 150.0 s in steps of 0.1
Thermal Reset (Configurable Digital Input)
Pickup Accuracy:
as per Voltage and Phase Current Inputs
Dual Setpoints
Timing Accuracy:
150 ms ±50 ms or ±0.5% of total time
Pre-Trip Data
Elements:
Trip (two trip zones)
Event Recorder
Test Input (Configurable Digital Input)
Waveform Memory
REACTIVE POWER
Block From Online:
0 to 5000 s in steps of 1
Fault Simulation
Pick- up Level:
0.02 to 1.50 × rated Mvar
(positive and negative)
VT Failure
Time Delay:
0.2 to 120.0 s in steps of 0.1
Breaker Failure
Pickup Accuracy:
see power metering
Trip Coil Monitor
Timing Accuracy:
±100ms or ±0.5% of total time
Generator Running Hours Alarm
Elements:
Trip and Alarm
IRIG-B Failure Alarm
REVERSE POWER
Trip Counter
ENVIRONMENTAL
Block From Online:
0 to 5000 s in steps of 1
Ambient Operating Temperature: –40°C to +60°C
Pick- up Level:
0.02 to 0.99 × rated MW
Ambient Storage Temperature: 40°C to +80°C.
Time Delay:
0.2 to 120.0 s in steps of 0.1
Humidity:
Pickup Accuracy:
see power metering
Altitude:
Up to 2000 m
Timing Accuracy:
±100 ms or ±0.5% of total time
Pollution Degree:
2
Elements:
Trip and Alarm
GE Multilin
489 Generator Management Relay
Up to 90%, noncondensing.
1-7
1.2 SPECIFICATIONS
1
1 INTRODUCTION
At temperatures lower than –20°C, the LCD contrast
may be impaired.
Model#:
NOTE
LONG-TERM STORAGE
Environment:
WARNING
WARNING
In addition to the above environmental
considerations, the relay should be
stored in an environment that is dry, corrosive-free, and not in direct sunlight.
Correct storage:
215.315
An external fuse must be used if supply voltage
exceeds 250V
Prevents premature component failures
caused by environmental factors such as
moisture or corrosive gases. Exposure
to high humidity or corrosive environments will prematurely degrade the electronic components in any electronic
device regardless of its use or manufacturer, unless specific precautions, such
as those mentioned in the Environmental
section above, are taken.
It is recommended that all relays be powered up once
per year, for one hour continuously, to avoid
deterioration
of
electrolytic
capacitors
and
subsequent relay failure.
CASE
TYPE TESTS
Dielectric Strength:
Per IEC 255-5 and ANSI/IEEE C37.90.
2.0 kV for 1 minute from relays, CTs,
VTs, power supply to Safety Ground
DO NOT CONNECT FILTER GROUND TO SAFETY
GROUND DURING TEST
WARNING
Insulation Resistance:
IEC255-5 500 V DC, from relays, CTs,
VTs, power supply to Safety Ground
DO NOT CONNECT FILTER GROUND
SAFETY GROUND DURING TEST
TO
WARNING
Transients:
ANSI C37.90.1 oscillatory (2.5 kV/
1 MHz); ANSI C37.90.1 Fast Rise (5 kV/
10 ns); Ontario Hydro A-28M-82;
IEC255-4 Impulse/High Frequency Disturbance Class III Level
Impulse Test:
IEC 255-5 0.5 Joule 5 kV
Fully drawout (Automatic CT shorts)
RFI:
50 MHz / 15 W Transmitter
Seal:
Seal provision
EMI:
Door:
Dust tight door
C37.90.2 Electromagnetic Interference
at 150 MHz and 450 MHz, 10V/m
Mounting:
Panel or 19" rack mount
IP Class:
IP20-X
Drawout:
PRODUCTION TESTS
Thermal Cycling:
Operational test at ambient, reducing to
–40°C and then increasing to 60°C
Dielectric Strength:
1.9 kV AC for 1 second or 1.6 kV AC for
1 minute, per UL 508.
WARNING
DO NOT CONNECT FILTER GROUND TO
SAFETY GROUND DURING ANY PRODUCTION
TESTS!
Static:
IEC 801-2 Static Discharge
Humidity:
90% non-condensing
Temperature:
–40°C to +60°C ambient
Environment:
IEC 68-2-38 Temperature/Humidity cycle
Vibration:
Sinusoidal Vibration 8.0 g for 72 hrs.
PACKAGING
Shipping Box:
12” × 11” × 10” (W × H × D)
30.5cm × 27.9cm × 25.4cm
Shipping Weight:
17 lbs Max / 7.7 kg
CERTIFICATION
ISO:
Manufactured under an ISO9001 registered system.
UL
FUSE
Current Rating:
3.15 A
UL:
Type:
5 × 20 mm Slo-Blo Littelfuse, High
Breaking Capacity
CSA:
CSA
CE:
Conforms to IEC 947-1, IEC 1010-1
1-8
489 Generator Management Relay
GE Multilin
2 INSTALLATION
2.1 MECHANICAL
2 INSTALLATION 2.1MECHANICAL
2.1.1 DESCRIPTION
The 489 is packaged in the standard GE Multilin SR series arrangement, which consists of a drawout unit and a companion
fixed case. The case provides mechanical protection to the unit, and is used to make permanent connections to all external
equipment. The only electrical components mounted in the case are those required to connect the unit to the external wiring. Connections in the case are fitted with mechanisms required to allow the safe removal of the relay unit from an energized panel, such as automatic CT shorting. The unit is mechanically held in the case by pins on the locking handle, which
cannot be fully lowered to the locked position until the electrical connections are completely mated. Any 489 can be
installed in any 489 case, except for custom manufactured units that are clearly identified as such on both case and unit,
and are equipped with an index pin keying mechanism to prevent incorrect pairings.
No special ventilation requirements need to be observed during the installation of the unit, but the unit should be wiped
clean with a damp cloth.
Figure 2–1: 489 DIMENSIONS
To prevent unauthorized removal of the drawout unit, a wire lead seal can be installed in the slot provided on the handle as
shown below. With this seal in place, the drawout unit cannot be removed. A passcode or setpoint access jumper can be
used to prevent entry of setpoints but still allow monitoring of actual values. If access to the front panel controls must be
restricted, a separate seal can be installed on the outside of the cover to prevent it from being opened.
Figure 2–2: DRAWOUT UNIT SEAL
Hazard may result if the product is not used for its intended purpose.
WARNING
GE Multilin
489 Generator Management Relay
2-1
2
2.1 MECHANICAL
2 INSTALLATION
2.1.2 PRODUCT IDENTIFICATION
Each 489 unit and case are equipped with a permanent label. This label is installed on the left side (when facing the front of
the relay) of both unit and case. The case label details which units can be installed.
The case label details the following information:
2
•
MODEL NUMBER
•
MANUFACTURE DATE
•
SPECIAL NOTES
The unit label details the following information:
•
MODEL NUMBER
•
OVERVOLTAGE CATEGORY
•
TYPE
•
INSULATION VOLTAGE
•
SERIAL NUMBER
•
POLLUTION DEGREE
•
FILE NUMBER
•
CONTROL POWER
•
MANUFACTURE DATE
•
OUTPUT CONTACT RATING
•
PHASE CURRENT INPUTS
•
SPECIAL NOTES
Figure 2–3: CASE AND UNIT IDENTIFICATION LABELS
2-2
489 Generator Management Relay
GE Multilin
2 INSTALLATION
2.1 MECHANICAL
2.1.3 INSTALLATION
The 489 case, alone or adjacent to another SR unit, can be installed in a standard 19-inch rack panel (see Figure 2–1: 489
Dimensions on page 2–1). Provision must be made for the front door to swing open without interference to, or from, adjacent equipment. The 489 unit is normally mounted in its case when shipped from the factory and should be removed before
mounting the case in the supporting panel. Unit withdrawal is described in the next section.
After the mounting hole in the panel has been prepared, slide the 489 case into the panel from the front. Applying firm pressure on the front to ensure the front bezel fits snugly against the front of the panel, bend out the pair of retaining tabs (to a
horizontal position) from each side of the case, as shown below. The case is now securely mounted, ready for panel wiring.
808704A1.CDR
Figure 2–4: BEND UP MOUNTING TABS
2.1.4 UNIT WITHDRAWAL AND INSERTION
TURN OFF CONTROL POWER BEFORE DRAWING OUT OR RE-INSERTING THE RELAY TO PREVENT MALOPERATION!
CAUTION
To remove the unit from the case:
1.
Open the cover by pulling the upper or lower corner of the right side, which will rotate about the hinges on the left.
2.
Release the locking latch, located below the locking handle, by pressing upward on the latch with the tip of a screwdriver.
Figure 2–5: PRESS LATCH TO DISENGAGE HANDLE
GE Multilin
489 Generator Management Relay
2-3
2
2.1 MECHANICAL
3.
2 INSTALLATION
Grasp the locking handle in the center and pull firmly, rotating the handle up from the bottom of the unit until movement
ceases.
2
Figure 2–6: ROTATE HANDLE TO STOP POSITION
4.
Once the handle is released from the locking mechanism, the unit can freely slide out of the case when pulled by the
handle. It may sometimes be necessary to adjust the handle position slightly to free the unit.
Figure 2–7: SLIDE UNIT OUT OF CASE
To insert the unit into the case:
1.
Raise the locking handle to the highest position.
2.
Hold the unit immediately in front of the case and align the rolling guide pins (near the hinges of the locking handle) to
the guide slots on either side of the case.
3.
Slide the unit into the case until the guide pins on the unit have engaged the guide slots on either side of the case.
If an attempt is made to install a unit into a non-matching case, the mechanical key will prevent full
insertion of the unit. Do not apply strong force in the following step or damage may result.
CAUTION
4.
Grasp the locking handle from the center and press down firmly, rotating the handle from the raised position toward the
bottom of the unit.
5.
When the unit is fully inserted, the latch will be heard to click, locking the handle in the final position.
2-4
489 Generator Management Relay
GE Multilin
2 INSTALLATION
2.1 MECHANICAL
2.1.5 TERMINAL LOCATIONS
2
Figure 2–8: TERMINAL LAYOUT
GE Multilin
489 Generator Management Relay
2-5
2.1 MECHANICAL
2 INSTALLATION
Table 2–1: 489 TERMINAL LIST
TERMINAL
A01
2
2-6
DESCRIPTION
TERMINAL
RTD #1 HOT
D21
DESCRIPTION
ASSIGNABLE SW. 06
A02
RTD #1 COMPENSATION
D22
ASSIGNABLE SW. 07
A03
RTD RETURN
D23
SWITCH COMMON
A04
RTD #2 COMPENSATION
D24
SWITCH +24 V DC
A05
RTD #2 HOT
D25
COMPUTER RS485 +
A06
RTD #3 HOT
D26
COMPUTER RS485 –
A07
RTD #3 COMPENSATION
D27
COMPUTER RS485 COMMON
A08
RTD RETURN
E01
R1 TRIP NC
A09
RTD #4 COMPENSATION
E02
R1 TRIP NO
A10
RTD #4 HOT
E03
R2 AUXILIARY COMMON
A11
RTD #5 HOT
E04
R3 AUXILIARY NC
A12
RTD #5 COMPENSATION
E05
R3 AUXILIARY NO
A13
RTD RETURN
E06
R4 AUXILIARY COMMON
A14
RTD #6 COMPENSATION
E07
R5 ALARM NC
A15
RTD #6 HOT
E08
R5 ALARM NO
A16
ANALOG OUT COMMON –
E09
R6 SERVICE COMMON
A17
ANALOG OUT 1 +
E10
NEUTRAL VT COMMON
A18
ANALOG OUT 2 +
E11
COIL SUPERVISION +
A19
ANALOG OUT 3 +
E12
IRIG-B +
A20
ANALOG OUT 4 +
F01
R1 TRIP COMMON
A21
ANALOG SHIELD
F02
R2 AUXILIARY NO
A22
ANALOG INPUT 24 V DC POWER SUPPLY +
F03
R2 AUXILIARY NC
A23
ANALOG INPUT 1 +
F04
R3 AUXILIARY COMMON
A24
ANALOG INPUT 2 +
F05
R4 AUXILIARY NO
A25
ANALOG INPUT 3 +
F06
R4 AUXILIARY NC
A26
ANALOG INPUT 4 +
F07
R5 ALARM COMMON
A27
ANALOG INPUT COMMON –
F08
R6 SERVICE NO
B01
RTD SHIELD
F09
R6 SERVICE NC
B02
AUXILIARY RS485 +
F10
NEUTRAL VT +
B03
AUXILIARY RS485 –
F11
COIL SUPERVISION –
B04
AUXILIARY RS485 COMMON
F12
IRIG-B –
C01
ACCESS +
G01
PHASE VT COMMON
C02
ACCESS –
G02
PHASE A VT •
C03
BREAKER STATUS +
G03
NEUTRAL PHASE A CT •
C04
BREAKER STATUS –
G04
NEUTRAL PHASE B CT •
D01
RTD #7 HOT
G05
NEUTRAL PHASE C CT •
D02
RTD #7 COMPENSATION
G06
OUTPUT PHASE A CT •
D03
RTD RETURN
G07
OUTPUT PHASE B CT •
D04
RTD #8 COMPENSATION
G08
OUTPUT PHASE C CT •
D05
RTD #8 HOT
G09
1A GROUND CT •
D06
RTD #9 HOT
G10
HGF GROUND CT •
D07
RTD #9 COMPENSATION
G11
FILTER GROUND
D08
RTD RETURN
G12
SAFETY GROUND
D09
RTD #10 COMPENSATION
H01
PHASE B VT •
D10
RTD #10 HOT
H02
PHASE C VT •
D11
RTD #11 HOT
H03
NEUTRAL PHASE A CT
D12
RTD #11 COMPENSATION
H04
NEUTRAL PHASE B CT
D13
RTD RETURN
H05
NEUTRAL PHASE C CT
D14
RTD #12 COMPENSATION
H06
OUTPUT PHASE A CT
D15
RTD #12 HOT
H07
OUTPUT PHASE B CT
D16
ASSIGNABLE SW. 01
H08
OUTPUT PHASE C CT
D17
ASSIGNABLE SW. 02
H09
1A GROUND CT
D18
ASSIGNABLE SW. 03
H10
HGF GROUND CT
D19
ASSIGNABLE SW. 04
H11
CONTROL POWER –
D20
ASSIGNABLE SW. 05
H12
CONTROL POWER +
489 Generator Management Relay
GE Multilin
2 INSTALLATION
2.2 ELECTRICAL
2.2ELECTRICAL
2.2.1 TYPICAL WIRING DIAGRAM
2
Figure 2–9: TYPICAL WIRING DIAGRAM
GE Multilin
489 Generator Management Relay
2-7
2.2 ELECTRICAL
2 INSTALLATION
2.2.2 GENERAL WIRING CONSIDERATIONS
A broad range of applications are available to the user and it is not possible to present typical connections for all possible
schemes. The information in this section will cover the important aspects of interconnections, in the general areas of instrument transformer inputs, other inputs, outputs, communications and grounding. See Figure 2–8: Terminal Layout and Table
2–1: 489 Terminal List for terminal arrangement, and Figure 2–9: Typical Wiring Diagram for typical connections.
2
Figure 2–10: TYPICAL WIRING (DETAIL)
2-8
489 Generator Management Relay
GE Multilin
2 INSTALLATION
2.2 ELECTRICAL
2.2.3 CONTROL POWER
Control power supplied to the 489 must match the installed switching power supply. If the applied voltage
does not match, damage to the unit may occur.
CAUTION
The order code from the terminal label on the side of the drawout unit specifies the nominal control voltage as one of the
following:
•
LO: 20 to 60 V DC; 20 to 48 V AC
•
HI: 90 to 300 V DC; 70 to 265 V AC
Ensure applied control voltage and rated voltage on drawout case terminal label match. For example, the HI power supply
will work with any DC voltage from 90 to 300 V, or AC voltage from 70 to 265 V. The internal fuse may blow if the applied
voltage exceeds this range.
Figure 2–11: CONTROL POWER CONNECTION
Extensive filtering and transient protection are built into the 489 to ensure proper operation in harsh industrial environments. Transient energy must be conducted back to the source through the filter ground terminal. A separate safety ground
terminal is provided for hi-pot testing.
All grounds MUST be hooked up for normal operation regardless of control power supply type.
NOTE
2.2.4 CURRENT INPUTS
a) PHASE CURRENT
The 489 has six phase current transformer inputs (three output side and three neutral end), each with an isolating transformer. There are no internal ground connections on the CT inputs. Each phase CT circuit is shorted by automatic mechanisms on the 489 case if the unit is withdrawn. The phase CTs should be chosen such that the FLA is no less than 50% of
the rated phase CT primary. Ideally, the phase CT primary should be chosen such that the FLA is 100% of the phase CT
primary or slightly less. This will ensure maximum accuracy for the current measurements. The maximum phase CT primary current is 50000 A.
The 489 will measure correctly up to 20 times the phase current nominal rating. Since the conversion range is large, 1 A or
5 A CT secondaries must be specified at the time of order such that the appropriate interposing CT may be installed in the
unit. CTs chosen must be capable of driving the 489 phase CT burden (see SPECIFICATIONS for ratings).
CAUTION
Verify that the 489 nominal phase current of 1 A or 5 A matches the secondary rating and connections of
the connected CTs. Unmatched CTs may result in equipment damage or inadequate protection. Polarity of
the phase CTs is critical for phase differential, negative sequence, power measurement, and residual
ground current detection (if used).
GE Multilin
489 Generator Management Relay
2-9
2
2.2 ELECTRICAL
2 INSTALLATION
b) GROUND CURRENT
2
The 489 has a dual primary isolating transformer for
ground CT connections. There are no internal ground connections on the ground current inputs. The ground CT circuits are shorted by automatic mechanisms on the case if
the unit is withdrawn. The 1 A tap is used for 1 A or 5 A
secondary CTs in either core balance or residual ground
configurations. If the 1 A tap is used, the 489 measures up
to 20 A secondary with a maximum ground CT ratio of
10000:1. The chosen ground CT must be capable of driving the ground CT burden (see SPECIFICATIONS).
The HGF ground CT input is designed for sensitive ground
current detection on high resistance grounded systems
where the GE Multilin HGF core balance CT (50:0.025) is
used. In applications such as mines, where earth leakage
current must be measured for personnel safety, primary
ground current as low as 0.25 A may be detected with the
GE Multilin HGF CT. Only one ground CT input tap should
be used on a given unit.
Only one ground input should be wired. The other
input should be unconnected.
NOTE
Figure 2–12: RESIDUAL GROUND CT CONNECTION
DO NOT INJECT OVER THE RATED CURRENT TO HGF TERMINAL (0.25 to 25 A PRIMARY)
CAUTION
The exact placement of a zero sequence CT to detect ground fault current is shown below. If the core balance CT is placed
over shielded cable, capacitive coupling of phase current into the cable shield may be detected as ground current unless
the shield wire is also passed through the CT window. Twisted pair cabling on the zero sequence CT is recommended.
Figure 2–13: CORE BALANCE GROUND CT INSTALLATION
2-10
489 Generator Management Relay
GE Multilin
2 INSTALLATION
2.2 ELECTRICAL
2.2.5 VOLTAGE INPUTS
The 489 has four voltage transformer inputs, three for generator terminal voltage and one for neutral voltage. There are no
internal fuses or ground connections on the voltage inputs. The maximum VT ratio is 240.00:1. The two possible VT connections for generator terminal voltage measurement are open delta or wye (see Figure 2–9: Typical Wiring Diagram on
page 2–7). The voltage channels are connected in wye internally, which means that the jumper shown on the delta-source
connection of the Typical Wiring Diagram, between the phase B input and the 489 neutral terminal, must be installed for
open delta VTs.
Polarity of the generator terminal VTs is critical for correct power measurement and voltage phase reversal
operation.
CAUTION
2.2.6 DIGITAL INPUTS
CAUTION
There are 9 digital inputs that are designed for dry contact connections only. Two of the digital inputs, Access and
Breaker Status have their own common terminal, the balance of the digital inputs share one common terminal (see
Figure 2–9: Typical Wiring Diagram on page 2–7).
In addition, the +24 V DC switch supply is brought out for control power of an inductive or capacitive proximity probe. The
NPN transistor output could be taken to one of the assignable digital inputs configured as a counter or tachometer. Refer to
the Specifications section of this manual for maximum current draw from the +24 V DC switch supply.
DO NOT INJECT VOLTAGES TO DIGITAL INPUTS. DRY CONTACT CONNECTIONS ONLY.
CAUTION
2.2.7 ANALOG INPUTS
Terminals are provided on the 489 for the input of four 0 to 1 mA, 0 to 20 mA, or 4 to 20 mA current signals (field programmable). This current signal can be used to monitor any external quantity such as: vibration, pressure, field current, etc. The
four inputs share one common return. Polarity of these inputs must be observed for proper operation The analog input circuitry is isolated as a group with the Analog Output circuitry and the RTD circuitry. Only one ground reference should be
used for the three circuits. Transorbs limit this isolation to ±36 V with respect to the 489 safety ground.
In addition, the +24 V DC analog input supply is brought out for control power of loop powered transducers. Refer to the
Specifications section of this manual for maximum current draw from this supply.
Figure 2–14: LOOP POWERED TRANSDUCER CONNECTION
GE Multilin
489 Generator Management Relay
2-11
2
2.2 ELECTRICAL
2 INSTALLATION
2.2.8 ANALOG OUTPUTS
The 489 provides four analog output channels, which when ordering, are selected to provide a full-scale range of either
0 to 1 mA (into a maximum 10 kΩ impedance), or 4 to 20 mA (into a maximum 600 Ω impedance). Each channel can be
configured to provide full-scale output sensitivity for any range of any measured parameter.
The analog output circuitry is isolated as a group with the Analog Input circuitry and the RTD circuitry. Only one ground reference should be used for the three circuits. Transorbs limit this isolation to ±36 V with respect to the 489 safety ground.
If a voltage output is required, a burden resistor must be connected at the input of the SCADA measuring device. Ignoring
the input impedance of the input:
V FULL-SCALE
R LOAD = ---------------------------------I MAX
(EQ 2.1)
For example, for a 0 to 1 mA input, if 5 V full scale corresponds to 1 mA, then RLOAD = 5 V / 0.001 A = 5000 Ω. For a
4 to 20 mA input, this resistor would be RLOAD = 5 V / 0.020 A = 250 Ω.
2.2.9 RTD SENSOR CONNECTIONS
The 489 can monitor up to 12 RTD inputs for Stator, Bearing, Ambient, or Other temperature monitoring. The type of each
RTD is field programmable as: 100 Ω Platinum (DIN 43760), 100 Ω Nickel, 120 Ω Nickel, or 10 Ω Copper. RTDs must be
three wire type. Every two RTDs shares a common return.
The 489 RTD circuitry compensates for lead resistance, provided that each of the three leads is the same length. Lead
resistance should not exceed 25 Ω per lead. Shielded cable should be used to prevent noise pickup in the industrial environment. RTD cables should be kept close to grounded metal casings and avoid areas of high electromagnetic or radio
interference. RTD leads should not be run adjacent to or in the same conduit as high current carrying wires.
489
RELAY
3 WIRE SHIELDED CABLE
Route cable in separate conduit from
current carrying conductors
CHASSIS
GROUND
RTD TERMINALS
AT GENERATOR
SHIELD
B1
HOT
A1
COMPENSATION
A2
RETURN
A3
RTD #1
RTD SENSING
2
As shown in Figure 2–9: Typical Wiring Diagram on page 2–7, these outputs share one common return. The polarity of
these outputs must be observed for proper operation. Shielded cable should be used, with only one end of the shield
grounded, to minimize noise effects.
RTD IN
GENERATOR
STATOR
OR
BEARING
OPTIONAL GROUND
Shield is internally
connected to safety
ground terminal G12
RTD
TERMINALS
Maximum total lead resistance
25 ohms (Platinum & Nickel RTDs)
3 ohms (Copper RTDs)
808761E4.CDR
Figure 2–15: RTD WIRING
NOTE
2-12
IMPORTANT NOTE: The RTD circuitry is isolated as a group with the Analog Input circuitry and the Analog Output
circuitry. Only one ground reference should be used for the three circuits. Transorbs limit this isolation to ±36 V with
respect to the 489 safety ground. If code requires that the RTDs be grounded locally at the generator terminal box,
that will also be the ground reference for the analog inputs and outputs.
489 Generator Management Relay
GE Multilin
2 INSTALLATION
2.2 ELECTRICAL
2.2.10 OUTPUT RELAYS
There are six Form C output relays (see the SPECIFICATIONS for ratings). Five of the six relays are always non-failsafe,
R6 Service is always failsafe. As failsafe, R6 relay will be energized normally and de-energize when called upon to operate.
It will also de-energize when control power to the 489 is lost and therefore, be in its operated state. All other relays, being
non-failsafe, will be de-energized normally and energize when called upon to operate. Obviously, when control power is lost
to the 489, these relays must be de-energized and therefore, they will be in their non-operated state. Shorting bars in the
drawout case ensure that when the 489 is drawn out, no trip or alarm occurs. The R6 Service output will however indicate
that the 489 has been drawn out. Each output relay has an LED indicator on the 489 front panel that comes on while the
associated relay is in the operated state.
•
R1 TRIP: The trip relay should be wired such that the generator is taken offline when conditions warrant. For a breaker
application, the NO R1 Trip contact should be wired in series with the Breaker trip coil.
Supervision of a breaker trip coil requires that the supervision circuit be paralleled with the R1 TRIP relay output contacts, as shown in Figure 2–9: Typical Wiring Diagram on page 2–7. With this connection made, the supervision input
circuits will place an impedance across the contacts that will draw a current of 2 to 5 mA (for an external supply voltage
from 30 to 250 V DC) through the breaker trip coil. The supervision circuits respond to a loss of this trickle current as a
failure condition. Circuit breakers equipped with standard control circuits have a breaker auxiliary contact permitting
the trip coil to be energized only when the breaker is closed. When these contacts are open, as detected by the
Breaker Status digital input, trip coil supervision circuit is automatically disabled. This logic provides that the trip circuit
is monitored only when the breaker is closed.
•
R2 AUXILIARY, R3 AUXILIARY, R4 AUXILIARY: The auxiliary relays may be programmed for numerous functions
such as, trip echo, alarm echo, trip backup, alarm or trip differentiation, control circuitry, etc. They should be wired as
configuration warrants.
•
R5 ALARM: The alarm relay should connect to the appropriate annunciator or monitoring device.
•
R6 SERVICE: The service relay will operate if any of the 489 diagnostics detect an internal failure or on loss of control
power. This output may be monitored with an annunciator, PLC or DCS.
The service relay NC contact may also be wired in parallel with the trip relay on a breaker application. This will provide
failsafe operation of the generator; that is, the generator will be tripped offline in the event that the 489 is not protecting
it. Simple annunciation of such a failure will allow the operator or the operation computer to either continue, or do a
sequenced shutdown.
WARNING
Relay contacts must be considered unsafe to touch when the system is energized! If the customer requires
the relay contacts for low voltage accessible applications, it is their responsibility to ensure proper insulation levels.
2.2.11 IRIG-B
IRIG-B is a standard time-code format that allows stamping of events to be synchronized among connected devices within
1 millisecond. The IRIG-B time codes are serial, width-modulated formats which are either DC level shifted or amplitude
modulated (AM). Third party equipment is available for generating the IRIG-B signal. This equipment may use a GPS satellite system to obtain the time reference enabling devices at different geographic locations to be synchronized.
Terminals E12 and F12 on the 489 unit are provided for the connection of an IRIG-B signal.
GE Multilin
489 Generator Management Relay
2-13
2
2.2 ELECTRICAL
2 INSTALLATION
2.2.12 RS485 COMMUNICATIONS PORTS
2
Two independent two-wire RS485 ports are provided. Up to 32 489 relays can be daisy-chained together on a communication channel without exceeding the driver capability. For larger systems, additional serial channels must be added. It is also
possible to use commercially available repeaters to increase the number of relays on a single channel to more than 32. A
suitable cable should have a characteristic impedance of 120 Ω (e.g. Belden #9841) and total wire length should not
exceed 4000 feet (approximately 1200 metres). Commercially available repeaters will allow for transmission distances
greater than 4000 ft.
Voltage differences between remote ends of the communication link are not uncommon. For this reason, surge protection
devices are internally installed across all RS485 terminals. Internally, an isolated power supply with an optocoupled data
interface is used to prevent noise coupling.
NOTE
To ensure that all devices in a daisy-chain are at the same potential, it is imperative that the common terminals of each RS485 port are tied together and grounded only once, at the master. Failure to do so may
result in intermittent or failed communications.
The source computer/PLC/SCADA system should have similar transient protection devices installed, either internally or
externally, to ensure maximum reliability. Ground the shield at one point only, as shown below, to avoid ground loops.
Correct polarity is also essential. All 489s must be wired with all ‘+’ terminals connected together, and all ‘–’ terminals connected together. Each relay must be daisy-chained to the next one. Avoid star or stub connected configurations. The last
device at each end of the daisy chain should be terminated with a 120 Ω ¼ W resistor in series with a 1 nF capacitor across
the ‘+’ and ‘–’ terminals. Observing these guidelines will result in a reliable communication system that is immune to system
transients.
Figure 2–16: RS485 COMMUNICATIONS WIRING
2-14
489 Generator Management Relay
GE Multilin
2 INSTALLATION
2.2 ELECTRICAL
2.2.13 DIELECTRIC STRENGTH
It may be required to test a complete motor starter for dielectric strength (“flash” or hi-pot”) with the 489 installed. The 489 is
rated for 1.9 kV AC for 1 second or 1.6 kV AC for 1 minute (per UL 508) isolation between relay contacts, CT inputs, VT
inputs, trip coil supervision, and the safety ground terminal G12. Some precautions are required to prevent damage to the
489 during these tests.
Filter networks and transient protection clamps are used between control power, trip coil supervision, and the filter ground
terminal G11. This filtering is intended to filter out high voltage transients, radio frequency interference (RFI), and electromagnetic interference (EMI). The filter capacitors and transient suppressors could be damaged by application continuous
high voltage. Disconnect filter ground terminal G11 during testing of control power and trip coil supervision. CT inputs, VT
inputs, and output relays do not require any special precautions. Low voltage inputs (<30 V), RTDs, analog inputs, analog
outputs, digital inputs, and RS485 communication ports are not to be tested for dielectric strength under any circumstance
(see below).
HGF3C
Figure 2–17: TESTING THE 489 FOR DIELECTRIC STRENGTH
GE Multilin
489 Generator Management Relay
2-15
2
2.2 ELECTRICAL
2 INSTALLATION
2
2-16
489 Generator Management Relay
GE Multilin
3 USER INTERFACES
3.1 FACEPLATE INTERFACE
3 USER INTERFACES 3.1FACEPLATE INTERFACE
3.1.1 DISPLAY
All messages appear on a 40-character liquid crystal display. Messages are in plain English and do not require the aid of an
instruction manual for deciphering. When the user interface is not being used, the display defaults to the user-defined status messages. Any trip or alarm automatically overrides the default messages and is immediately displayed.
3.1.2 LED INDICATORS
489 STATUS
GENERATOR STATUS OUTPUT RELAYS
489 IN SERVICE
BREAKER OPEN
R1 TRIP
SETPOINT ACCESS
BREAKER CLOSED
R2 AUXILIARY
COMPUTER RS232
HOT STATOR
R3 AUXILIARY
COMPUTER RS485
NEG. SEQUENCE
R4 AUXILIARY
AUXILIARY RS485
GROUND
R5 ALARM
ALT. SETPOINTS
LOSS OF FIELD
R6 SERVICE
RESET
POSSIBLE
VT FAILURE
MESSAGE
BREAKER FAILURE
3
808732A1.CDR
Figure 3–1: 489 LED INDICATORS
a) 489 STATUS LED INDICATORS
•
489 IN SERVICE: Indicates that control power is applied, all monitored input/output and internal systems are OK, the
489 has been programmed, and is in protection mode, not simulation mode. When in simulation or testing mode, the
LED indicator will flash.
•
SETPOINT ACCESS: Indicates that the access jumper is installed and passcode protection has been satisfied. Setpoints may be altered and stored.
•
COMPUTER RS232: Flashes when there is any activity on the RS232 communications port. Remains on continuously
if incoming data is valid.
•
COMPUTER RS485 / AUXILIARY RS485: Flashes when there is any activity on the computer/auxiliary RS485 communications port. These LEDs remains on continuously if incoming data is valid and intended for the slave address
programmed in the relay.
•
ALT. SETPOINTS: Flashes when the alternate setpoint group is being edited and the primary setpoint group is active.
Remains on continuously if the alternate setpoint group is active. The alternate setpoint group feature is enabled as
one of the assignable digital inputs. The alternate setpoints group can be selected by setting the S3 DIGITAL INPUTS /
DUAL SETPOINTS / ACTIVATE SETPOINT GROUP setpoint to "Group 2".
•
RESET POSSIBLE: A trip or latched alarm may be reset. Pressing the
•
MESSAGE: Indicator flashes when a trip or alarm occurs. Press the NEXT key to scroll through the diagnostic messages. Remains solid when setpoint and actual value messages are being viewed. Pressing the NEXT key returns the
display to the default messages.
RESET
key clears the trip/alarm.
b) GENERATOR STATUS LED INDICATORS
•
BREAKER OPEN: Uses the breaker status input signal to indicate that the breaker is open and the generator is offline.
•
BREAKER CLOSED: Uses the breaker status input signal to indicate that the breaker is closed and the generator is
online.
•
HOT STATOR: Indicates that the generator stator is above normal temperature when one of the stator RTD alarm or
trip elements is picked up or the thermal capacity alarm element is picked up.
•
NEG. SEQUENCE: Indicates that the negative sequence current alarm or trip element is picked up.
•
GROUND: Indicates that at least one of the ground overcurrent, neutral overvoltage (fundamental), or neutral undervoltage (3rd harmonic) alarm/trip elements is picked up.
•
LOSS OF FIELD: Indicates that at least one of the reactive power (kvar) or field-breaker discrepancy alarm/trip elements is picked up.
GE Multilin
489 Generator Management Relay
3-1
3.1 FACEPLATE INTERFACE
3 USER INTERFACES
•
VT FAILURE: Indicates that the VT fuse failure alarm is picked up.
•
BREAKER FAILURE: Indicates that the breaker failure or trip coil monitor alarm is picked up.
c) OUTPUT RELAY LED INDICATORS
3
•
R1 TRIP: R1 Trip relay has operated (energized).
•
R2 AUXILIARY: R2 Auxiliary relay has operated (energized).
•
R3 AUXILIARY: R3 Auxiliary relay has operated (energized).
•
R4 AUXILIARY: R4 Auxiliary relay has operated (energized).
•
R5 ALARM: R5 Alarm relay has operated (energized).
•
R6 SERVICE: R6 Service relay has operated (de-energized, R6 is fail-safe, normally energized).
3.1.3 RS232 PROGRAM PORT
This port is intended for connection to a portable PC. Setpoint files may be created at any location and downloaded through
this port with the 489PC software. Local interrogation of setpoints and actual values is also possible. New firmware may be
downloaded to the 489 flash memory through this port. Upgrading the relay firmware does not require a hardware
EEPROM change.
3.1.4 KEYPAD
a) DESCRIPTION
The 489 messages are organized into pages under the headings SETPOINTS and ACTUAL VALUES. The SETPOINT key navigates through the programmable parameters (setpoints) page headers. The ACTUAL key navigates through the measured
parameters (actual values) page headers.
•
Each page is divided into logical subgroups of messages. The
through these subgroups.
•
The
•
The ESCAPE key is also dual purpose. It may be used to exit the subgroups or to return an altered setpoint to its original
value before it has been stored.
•
The VALUE
and VALUE
keys scroll through variables in setpoint programming mode and will increment/decrement
numerical setpoint values. These values may also be entered with the numeric keypad.
•
The
ENTER
HELP
MESSAGE
and
MESSAGE
keys are used to navigate
key is dual purpose. It is used to enter the subgroups or store altered setpoint values.
key may be pressed at any time for context sensitive help messages.
808711A1.CDR
Figure 3–2: 489 KEYPAD
b) ENTERING ALPHANUMERIC TEXT
There are several places where custom text messages may be programmed for specific applications. One example is the
The following example demonstrates how to enter alphanumeric text messages. To enter the text,
"Generator#1", perform the following procedure:
MESSAGE SCRATCHPAD.
1.
3-2
Press the decimal key [.] to enter text edit mode.
489 Generator Management Relay
GE Multilin
3 USER INTERFACES
2.
Press the
3.
Repeat Step 2 for the remaining characters: e, n, e, r, a, t, o, r, #, and 1.
4.
Press
VALUE
ENTER
or
3.1 FACEPLATE INTERFACE
VALUE
key until "G" appears, then press the decimal key to advance the cursor.
to store the text message.
c) ENTERING +/– SIGNS
The 489 does not have a ‘+’ or ‘–’ key. Negative numbers may be entered in one of the following two ways:
•
Press the
•
Once a numeric setpoint is entered (after pressing at least one numeric key), press the
change the sign, if applicable.
VALUE
or
VALUE
keys the scroll through the setpoint range, including any negative numbers.
VALUE
or
VALUE
key to
d) SETPOINT ENTRY
To store setpoints with the keypad, Terminals C1 and C2 (access terminals) must be shorted (a key switch may be used for
security). There is also a setpoint passcode feature that can restrict setpoint access from the keypad and communication
ports. If activated, the passcode must be entered before changing the setpoint values. A passcode of "0" turns off the passcode feature and only the access jumper is required to change setpoints. If no setpoint changes are made for 30 minutes,
access to setpoint values will be restricted until the passcode is entered again. To prevent setpoint access before the 30
minutes expiry, the unit may be turned off and back on, the access jumper may be removed, or the SETPOINT ACCESS setpoint may be changed to "Restricted". The passcode for the front panel keypad cannot be entered until terminals C1 and
C2 are shorted. The Setpoint Access LED Indicator will be on if setpoint access is enabled for the front panel keypad.
The following procedure may be used to access and alter any setpoint message. This specific example will refer to entering
a valid passcode in order to allow access to setpoints if the passcode was "489"
1.
The 489 programming is broken down into pages by logical groups. Press SETPOINT to cycle through the setpoint pages
until the desired page appears on the screen. Press MESSAGE
to enter a page.
 SETPOINTS
 S1 489 SETUP
2.
Each page is broken further into subgroups. Press the MESSAGE
and MESSAGE
keys to cycle through subgroups until
the desired subgroup appears on the screen. Press ENTER to enter a subgroup.
PASSCODE
[ENTER] for more
3.
Each sub-group has one or more associated setpoint messages. Press the MESSAGE
through setpoint messages until the desired setpoint message appears on the screen.
and
MESSAGE
keys to cycle
ENTER PASSCODE FOR
ACCESS:
4.
The majority of setpoints may be may be altered by pressing the VALUE
and VALUE
keys until the desired value
appears then pressing ENTER . Numeric setpoints may also be entered directly through the keypad. If an entered setpoint value is out of range, the original setpoint value reappears. If an out-of-step setpoint is entered, an adjusted value
is stored (e.g. a value of 101 for a setpoint that steps 95, 100, 105 is stored as 100). If a mistake is made entering the
new value, pressing ESCAPE resets the setpoint to its original value. Text editing is described in detail in Section b):
Entering Alphanumeric Text on page 3–2. When a new setpoint is successfully stored, the NEW SETPOINT HAS BEEN
STORED message flashes on the display.
5.
Press the 4, 8, and 9 keys, then press
and the display returns to:
ESCAPE .
The NEW SETPOINT HAS BEEN STORED message is briefly displayed
SETPOINT ACCESS:
PERMITTED
6.
Press
GE Multilin
ESCAPE
to exit the subgroup. Pressing
ESCAPE
numerous times always brings the cursor to the top of the page.
489 Generator Management Relay
3-3
3
3.2 SOFTWARE INTERFACE
3 USER INTERFACES
3.2SOFTWARE INTERFACE
WARNING
3.2.1 REQUIREMENTS
The 489PC software is not compatible with Mods and could cause errors if setpoints are edited. However, it
can be used to upgrade older versions of relay firmware. When doing this, previously programmed setpoints will be erased. They should be saved beforehand to a file for reprogramming with the new firmware.
The following minimum requirements must be met for the 489PC software to properly operate on a computer.
3
•
Processor:
minimum 486, Pentium or higher recommended
•
Memory:
minimum 4 MB, 16 MB recommended
minimum 540K of conventional memory
•
Hard Drive:
20 MB free space required before installation of software.
•
O/S:
Windows 3.1, Windows 3.11 for Workgroups, Windows 95/98, or Windows NT.
Windows 3.1 users must ensure that SHARE.EXE is installed.
NOTE
3-4
489PC may be installed from either the GE Multilin Products CD or the GE Multilin website at www.GEindustrial.com/multilin. If you are using legacy equipment without web access or a CD, 3.5” floppy disks can be ordered
from the factory.
489 Generator Management Relay
GE Multilin
3 USER INTERFACES
3.2 SOFTWARE INTERFACE
3.2.2 INSTALLATION/UPGRADE
a) CHECKING IF INSTALLATION/UPGRADE IS REQUIRED
If 489PC is already installed, run the program and use the following procedure to check if it needs upgrading:
1.
While 489PC is running, insert the GE Multilin Products CD and allow it to autostart (alternately, load the D:\index.htm
file from the CD into your default web browser), OR
Go to the GE Multilin website at www.GEindustrial.com/multilin (preferred method)
2.
Click the “Software” menu item and select “489 Generator Management Relay” from the list of products shown.
3.
Verify that the version shown is identical to the installed version (see below). The Help > About 489PC menu item displays the current version of 489PC.
3
If these two versions do not match,
then the 489PC software must
be upgraded.
808745A1.CDR
GE Multilin
489 Generator Management Relay
3-5
3.2 SOFTWARE INTERFACE
3 USER INTERFACES
b) INSTALLING/UPGRADING 489PC
Installation/upgrade of the 489PC software is accomplished as follows:
1.
Ensure that Windows is running on the local PC
2.
Insert the GE Multilin Products CD into your computer or point your web browser to the GE Multilin website at
www.GEindustrial.com/multilin. With Windows95/98, the Products CD will launch the welcome screen (see figure
below) automatically; with Windows 3.1, open the Products CD by opening the index.htm file in the CD root directory
with a web browser.
The Products CD is essentially a “snapshot” of the GE Multilin website at the date printed on the CD. As such, the procedures for installation from the CD or the website are identical; however, to ensure that the newest version of 489PC is
installed, installation from the web is preferred.
3
Specific resources can be
accessed from this menu
Select 489 from the
Products list to proceed
directly to the 489
Generator Management
Relay Product Page
Technical publications
and support for the 489
can be accessed through
the Support menu
Figure 3–3: GE MULTILIN WELCOME SCREEN
3.
Click the Index by Product Name item from the Products menu of the left side of the page then select 489 Generator
Management Relay from the product list to open the 489 product page.
4.
Click the Software item from the Resources list to open the 489 software page.
5.
The latest version of 489PC will be shown (see previous page). Select the Download 489PC Software item to download the installation program. Run the installation program and follow the prompts to install the 489PC software. When
complete, a new GE Multilin group window will appear containing the 489PC icon.
3-6
489 Generator Management Relay
GE Multilin
3 USER INTERFACES
3.2 SOFTWARE INTERFACE
3.2.3 CONFIGURATION
1.
Connect the computer running 489PC to the relay via one of the RS485 ports (see Section 2.2.12: RS485 Communications Ports on page 2–14 for wiring diagram and additional information) or directly via the RS232 front port.
2.
Start 489PC. When starting, the software attempts to communicate with the relay. If communications are established,
the relay graphic shown on the monitor will display the same information as the actual relay. That is, the LED status
and display information will also match that of the actual relay.
3.
If 489PC cannot establish communications, the following message will appear:
3
4.
Select OK to edit the communications settings (or alternately, select the Communications > Computer menu item to
edit communications settings at any time. The COMMUNICATIONS/COMPUTER dialog box will appear containing the
various communications settings. The settings should be modified as follows:
Set the Startup Mode based on user preference. In “Communicate with Relay” mode, 489PC will attempt
to establish communications immediately upon startup. While in the “File mode /w default settings”, 489PC
waits for the user to click the ON button before attempting communications – this mode is preferred when
the 489PC is being used without an attached 489 relay.
Set Control Type to match the type of RS232/RS485 converter. If connected through the 489 front panel
RS232 port, select “No Control Type”. If connected through a GE Multilin F485 converter unit, select
“MULTILIN RS232/RS485 CONVERTOR”. If connected through a modem, select “Modem”. If a thirdparty RS232/RS485 converter is being used, select the appropriate control type from the available list based
on the manufacturer’s specifications.
Set Parity to match the 489 PARITY setpoint (see S1 489 SETUP). If connected through the 489 front panel
RS232 port, set to “None”.
Set Baud Rate to match the 489 BAUD RATE setpoint (see S1 489 SETUP).
Set Communcation Port # to the COM port on your local PC where the 489 relay is connected (e.g. COM1
or COM2). On most computers, COM1 is used by the mouse device and as such COM2 is usually
available for communications.
Set Slave Address to match the 489 SLAVE ADDRESS setpoint (see S1 489 SETUP).
808744A1.CDR
Figure 3–4: COMMUNICATION/COMPUTER DIALOG BOX
5.
To begin communications, click the ON button. The status section indicates the communications status. The message
“489PC is now talking to a 489” is displayed when communications are established. As well, the bottom right corner of
the 489PC window will indicate “Communicating.”
GE Multilin
489 Generator Management Relay
3-7
3.2 SOFTWARE INTERFACE
3 USER INTERFACES
3.2.4 USING 489PC
a) SAVING SETPOINTS TO A FILE
Setpoints must be saved to a file on the local PC before performing any firmware upgrades. Saving setpoints is also highly
recommended before making any setpoint changes or creating new setpoint files. The following procedure illustrates how
to save setpoint files.
1.
Select the File > Properties menu item. The dialog box below appears, allowing for the configuration of the 489PC
software for the correct firmware version. 489PC requires the correct software version when creating a setpoint file to
ensure that setpoints not available in a particular version are not downloaded into the relay.
2.
When the correct firmware version is chosen, select the File > Save As menu item. This launches the dialog box
shown below. Enter or select the filename under which the setpoints are to be saved. All 489 setpoint files should have
the extension 489 (for example, gen1.489). Click OK to proceed.
3.
The software reads all relay setpoint values and stores them in the selected file.
3
b) UPGRADING THE 489 FIRMWARE
Prior to downloading new firmware into the 489, it is necessary to save the 489 setpoints to a file (see Section 3.2.4: Using
489PC on page 3–8. Loading new firmware into the 489 flash memory is accomplished as follows:
1.
Ensure the computer is connected to the 489 via the front RS232 port and that communications have been established. Save the current setpoints to a file using the procedure outlined in the previous section.
2.
Select the Communications > Upgrade Firmware menu item.
3.
A warning message will appear (remember that all previously programmed setpoints will be erased). Click Yes to proceed or No to exit.
4.
Next, 489PC will request the name of the new firmware file. Locate the appropriate file by changing drives and/or directories until a list of names appears in the list box. 489 firmware files have the following format:
3-8
489 Generator Management Relay
GE Multilin
3 USER INTERFACES
3.2 SOFTWARE INTERFACE
32 I 151 A8 .000
Modification Number (000 = none)
GE Multilin use only
Firmware Revision
Required 489 hardware revision
Product code (32 = 489 Generator Management Relay)
808733A1.CDR
5.
The 489PC software automatically lists all filenames beginning with 32. Select the appropriate file and click OK to continue.
6.
489PC prompts with the following dialog box. This will be the last chance to cancel the firmware upgrade before the
flash memory is erased. Click Yes to continue or No to cancel the upgrade.
7.
The software automatically puts the relay into “upload mode” and begins loading the selected firmware file. Upon completion, the relay is placed back into “normal mode”.
8.
When the 489 firmware update is complete, the relay will not be in service and will require programming. To communicate with the relay via the RS485 ports, the Slave Address, Baud Rate, and Parity will have to be manually programmed. When communications is established, the saved setpoints will have to be reloaded back into the 489. See
the next section for details.
c) LOADING SETPOINTS FROM A FILE
WARNING
An error message will occur when attempting to download a setpoint file with a revision number that does
not match the relay firmware. If the firmware has been upgraded since saving the setpoint file, see Section
e): Upgrading Setpoint Files to a New Revision on page 3–10 for instructions on changing the revision
number of a setpoint file.
The following procedure demonstrates how to load setpoints from a file:
1.
Select the File > Open menu item.
2.
489PC will launch the Open window and list all filenames in the 489 default directory with the 489 extension. Select the
setpoint file to download and click OK to continue.
3.
Select the File > Send Info to Relay menu item. 489PC will prompt to confirm or cancel the setpoint file load. Click
Yes to update the 489 setpoints.
GE Multilin
489 Generator Management Relay
3-9
3
3.2 SOFTWARE INTERFACE
3 USER INTERFACES
d) ENTERING SETPOINTS
The following example illustrates how setpoints are entered and edited with the 489PC software.
1.
Select the Setpoint > System Setup menu item.
2.
Click the Current Sensing tab to edit the S2 SYSTEM SETUP  CURRENT SENSING setpoints. 489PC displays the following window:
3.
For setpoints requiring numerical values, e.g. PHASE CT PRIMARY, clicking anywhere within the setpoint box launches a
numerical keypad showing the old value, range, and setpoint value increment.
4.
Alternately, numerical setpoint values may also be chosen by scrolling with the up/down arrow buttons at the end of the
setpoint box. The values increment and decrement accordingly.
5.
For setpoints requiring non-numerical pre-set values (e.g. GROUND CT TYPE above), clicking anywhere within the setpoint value box displays a drop down selection menu.
6.
For setpoints requiring an alphanumeric text string (e.g. message scratchpad messages), the value may be entered
directly within the setpoint value box.
3
e) UPGRADING SETPOINT FILES TO A NEW REVISION
It may be necessary to upgrade the revision code for a previously saved setpoint file after the 489 firmware has been
upgraded.
1.
Establish communications with the 489 relay.
2.
Select the Actual > Product Information menu item and record the Flash Revision identifier of the relay firmware.
For example, 32H150A8.000, where 150 is the Flash Revision identifier and refers to firmware revision 1.50.
3-10
489 Generator Management Relay
GE Multilin
3 USER INTERFACES
3.2 SOFTWARE INTERFACE
3.
Select the File > Open menu item and enter the location and file name of the saved setpoint file. When the file is
opened, the 489PC software will be in “File Editing” mode and “Not Communicating”.
4.
Select the File > Properties menu item and note the version code of the setpoint file. If the Version code of the setpoint file (e.g. 1.5X shown below) is different than the Flash Revision code noted in step 2, select a Version code
which matches the Flash Revision code from the pull-down menu.
For example,
If the firmware revision is:
and the current setpoint file revision is:
change the setpoint file revision to:
32H150A8.000
1.30
1.5X
3
5.
Select the File > Save menu item to save the setpoint file in the new format.
See Section c): Loading Setpoints from a File on page 3–9 for instructions on downloading this setpoint file to the 489.
f) PRINTING SETPOINTS AND ACTUAL VALUES
Use the following procedure to print a complete list of setpoint values.
1.
Select the File > Open menu item and open a previously saved setpoint file OR establish communications with the
489.
2.
Select the File > Print Setup menu item.
3.
Select either Setpoints (All) or Setpoints (Enabled Features) and click OK.
4.
Select the File > Print menu item to print the 489 setpoints.
Use the following procedure to print a complete list of actual values.
1.
Establish communications with the 489.
2.
Select the File > Print Setup menu item.
3.
Select Actual Values and click OK.
4.
Select the File > Print menu item to print the 489 actual values.
GE Multilin
489 Generator Management Relay
3-11
3.2 SOFTWARE INTERFACE
3 USER INTERFACES
3.2.5 TRENDING
Trending from the 489 can be accomplished via the 489PC program. Many different parameters can be trended and
graphed at sampling periods ranging from 1 second up to 1 hour.
The parameters which can be Trended by the 489PC software are:
3
Currents/Voltages:
Phase Currents A, B, and C
Generator Load
Ground Current
System Frequency
Volts/Hz
Neutral Voltage (3rd harmonic)
Neutral Currents A, B, and C
Negative Sequence Current
Differential Currents A, B, and C
Voltages Vab, Vbc, Vca Van, Vbn, and Vcn
Neutral Voltage (fundamental)
Terminal Voltage (3rd harmonic)
Power:
Power Factor
Reactive Power (Mvar)
Positive Watthours
Negative Varhours
Real Power (MW)
Apparent Power (MVA)
Positive Varhours
Temperature:
Hottest Stator RTD
RTDs 1 through 12
Thermal Capacity Used
Others:
Analog Inputs 1, 2, 3, and 4
Tachometer
1.
With the 489PC running and communications established, select the Actual > Trending menu item to open the trending
window.
2.
Click Setup to enter the Graph Attribute page.
3.
Select the graphs to be displayed with the pull-down menus beside each Description. Change the Color, Style, Width,
Group#, and Spline sections as desired. Select the same Group# to scale all parameters together.
4.
Click Save to store the graph attributes and OK to close the window.
Figure 3–5: GRAPH ATTRIBUTE WINDOW – TRENDING
3-12
489 Generator Management Relay
GE Multilin
3 USER INTERFACES
5.
3.2 SOFTWARE INTERFACE
Select the Sample Rate through the pull-down menu, click the checkboxes of the graphs to be displayed, then click
RUN to begin the trending sampling.
MODE SELECT
LEVEL
WAVEFORM
Click on these buttons to view
Cursor Line 1, Cursor Line 2, or
Delta (difference) values for the graph
Displays the value of the graph
at the active Cursor Line
The trended data
from the 469 relay
3
CHECK BOXES
BUTTONS
CURSOR LINES
Toggle the Check Box to
view the desired graphs.
Print, Setup (to edit Graph Attributes)
Zoom In, Zoom Out
To move lines, move mouse pointer
over the cursor line. Click and hold the
left mouse button and drag the cursor
line to the new location
808726A2.CDR
Figure 3–6: TRENDING
6.
The Trending File Setup button can be used to write graph data to a standard spreadsheet format. Ensure that the
Write trended data to the above file checkbox is checked and that the Sample Rate is a minimum of 5 seconds.
Figure 3–7: TRENDING FILE SETUP
GE Multilin
489 Generator Management Relay
3-13
3.2 SOFTWARE INTERFACE
3 USER INTERFACES
3.2.6 WAVEFORM CAPTURE
The 489PC software can be used to capture waveforms from the 489 at the instant of a trip. A maximum of 64 cycles can
be captured and the trigger point can be adjusted to anywhere within the set cycles. A maximum of 16 waveforms can be
buffered (stored) with the buffer/cycle trade-off.
The waveforms captured are: Phase Currents A, B, and C; Neutral Currents A, B, and C; Ground Current; and Phase Voltages A-N, B-N, and C-N
3
1.
With 489PC running and communications established, select the Actual > Waveform Capture menu item to open the
waveform capture window.
2.
The phase A current waveform for the last 489 trip will appear. The date and time of the trip is displayed at the top of
the window. The red vertical line indicates the trigger point of the relay.
3.
Press the Setup button to enter the Graph Attribute page. Program the graphs to be displayed with the pull-down menu
beside each graph description. Change the Color, Style, Width, Group#, and Spline selections as desired. Select the
same Group# to scale all parameters together.
4.
Click Save to store these graph attributes, then click OK to close the window.
5.
Select the graphs to display by checking the appropriate checkboxes.
6.
The Save button stores the current image on the screen, and Open recalls a saved image. Print will copy the window
to the system printer.
MODE SELECT
Click to view Cursor Lines 1, 2, or
Difference (Delta) values for the
graph
TRIGGER CAUSE
Displays the cause of
the trigger
TRIGGER
Click to manually trigger
and capture waveforms
DATE/TIME
Displays the date and time
of the trigger cause
WAVEFORM
The relay
waveform data
LEVEL
Displays the
value of the
graph at the
solid cursor
line
CHECK BOX
Toggle the check boxes
to view desired graphs
BUTTONS
Print, Help, Save (to save
graph to a file), Open (to
open a graph file), Zoom In
and Out
CURSOR LINES
To move lines, move the mouse
pointer over the cursor line; hold
the left mouse button and drag the
cursor line to a new location
808730A2.CDR
Figure 3–8: WAVEFORM CAPTURE
3-14
489 Generator Management Relay
GE Multilin
3 USER INTERFACES
3.2 SOFTWARE INTERFACE
3.2.7 PHASORS
The 489PC software can be used to view the phasor diagram of three phase currents and voltages. The phasors are for:
•
Phase Voltages A, B, and C
•
Phase Currents A, B, and C
•
Impedance ZLoss
1.
With 489PC running and communications established, open the Metering Data window by selecting the Actual >
Metering Data menu item then clicking the Phasors tab. The phasor diagram and the values of the voltage phasors are
displayed.
Longer arrows are the voltage phasors, shorter arrows are the current phasors.
3
NOTE
2.
Va and Ia are the references (i.e. zero degree phase). The lagging angle is clockwise.
VOLTAGE LEVEL
CURRENT PHASOR
VOLTAGE PHASOR
Displays the value and
the angle of the voltage
phasors
Short arrow
Long arrow
808713A1.CDR
CURRENT LEVEL
Displays the value and angle
of the current phasors
Figure 3–9: PHASORS
GE Multilin
489 Generator Management Relay
3-15
3.2 SOFTWARE INTERFACE
3 USER INTERFACES
3.2.8 EVENT RECORDER
The 489 event recorder can be viewed through the 489PC software. The event recorder stores generator and system information each time an event occurs (e.g. a generator trip). Up to 40 events can be stored, where EVENT01 is the most recent
and EVENT40 is the oldest. EVENT40 is overwritten whenever a new event occurs.
3
1.
With 489PC running and communications established, select the Actual > Event Recording menu item to open the
Event Recording window. This window displays the list of events with the most current event displayed first (see the
figure below).
2.
Press the View Data button to see details of selected events.
3.
The Event Recorder Selector at the top of the View Data window scrolls through different events. Select Save to store
the details of the selected events to a file.
4.
Select Print to send the events to the system printer, and OK to close the window.
DISPLAY
EVENT LISTING
Displays the date of last event and
the total number of events since
last clear
List of events with the most
recent displayed on top
VIEW DATA
Click to display the details
of selected events
EVENT SELECT BUTTONS
CLEAR EVENTS
Push the All button to select all events
Push the None button to clear all selections
Click the Clear Events button to
clear the Event Listing from memory
808707A1.CDR
Figure 3–10: 489PC EVENT RECORDER
3-16
489 Generator Management Relay
GE Multilin
3 USER INTERFACES
3.2 SOFTWARE INTERFACE
3.2.9 TROUBLESHOOTING
This section provides some procedures for troubleshooting the 489PC when troubles are encountered within the Windows
environment (for example, General Protection Fault (GPF), Missing Window, Problems in Opening or Saving Files,
and Application Error messages).
If the 489PC software causes Windows system errors:
1.
Check system resources:
•
In Windows 95/98, right-click on the My Computer icon and click on the Performance tab.
•
In Windows 3.1/3.11, select the Help > About Program Manager menu item from the Program Manager window.
Verify that the available system resources are 60% or higher. If they are lower, close any other programs that are not
being used.
2.
The threed.vbx file in the Windows directory structure is used by the 489PC software (and possibly other Windows™ programs). Some older versions of this file are not compatible with 489PC; therefore it may be necessary to
update this file with the latest version included with 489PC. After installation of the 489PC software, this file will be
located in \GEPM\489PC\threed.vbx.
3.
To update the threed.vbx file, locate the currently used file and make a backup of it, e.g. threed.bak.
4.
A search should be conducted to locate any threed.vbx files on the local PC hard drive. The file which needs replacing is the one located in the \windows or the \windows\system directory.
5.
Replace the original threed.vbx with \GEPM\489PC\threed.vbx. Ensure that the new file is copied to the same
directory where the original one was.
6.
If Windows™ prevents the replacing of this file, restart the PC and replace the file before any programs are opened.
7.
Restart Windows™ for these changes to take full effect.
GE Multilin
489 Generator Management Relay
3-17
3
3.2 SOFTWARE INTERFACE
3 USER INTERFACES
3
3-18
489 Generator Management Relay
GE Multilin
4 SETPOINTS
4.1 OVERVIEW
4 SETPOINTS 4.1OVERVIEW
ð
 S1 SETPOINTS
 489 SETUP
4.1.1 SETPOINT MESSAGE MAP
ENTER
ð
ESCAPE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
 PASSCODE
 [ENTER] for more
See page 4–7.
 PREFERENCES
 [ENTER] for more
See page 4–7.
 SERIAL PORT
 [ENTER] for more
See page 4–8.
 REAL TIME CLOCK
 [ENTER] for more
See page 4–9.
 DEFAULT MESSAGES
 [ENTER] for more
See page 4–9.
 MESSAGE SCRATCHPAD
 [ENTER] for more
See page 4–10.
 CLEAR DATA
 [ENTER] for more
See page 4–11.
 CURRENT SENSING
 [ENTER] for more
See page 4–12.
 VOLTAGE SENSING
 [ENTER] for more
See page 4–12.
 GEN PARAMETERS
 [ENTER] for more
See page 4–13.
 SERIAL START/STOP
 [ENTER] for more
See page 4–13.
 BREAKER STATUS
 [ENTER] for more
See page 4–14.
 GENERAL INPUT A
 [ENTER] for more
See page 4–15.
4
ESCAPE
MESSAGE
ð
 S2 SETPOINTS
 SYSTEM SETUP
ENTER
ð
ESCAPE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ð
 S3 SETPOINTS
 DIGITAL INPUTS
ENTER
ESCAPE
ESCAPE
MESSAGE
ð
↓
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
GE Multilin
 GENERAL INPUT G
 [ENTER] for more
 REMOTE RESET
 [ENTER] for more
See page 4–16.
 TEST INPUT
 [ENTER] for more
See page 4–16.
 THERMAL RESET
 [ENTER] for more
See page 4–16.
 DUAL SETPOINTS
 [ENTER] for more
See page 4–16.
 SEQUENTIAL TRIP
 [ENTER] for more
See page 4–17.
489 Generator Management Relay
4-1
4.1 OVERVIEW
4 SETPOINTS
 FIELD-BKR DISCREP.
 [ENTER] for more
See page 4–18.
 TACHOMETER
 [ENTER] for more
See page 4–18.
 WAVEFORM CAPTURE
 [ENTER] for more
See page 4–19.
 GND SWITCH STATUS
 [ENTER] for more
See page 4–19.
ð
 RELAY RESET MODE
 [ENTER] for more
See page 4–20.
ð
 OVERCURRENT ALARM
 [ENTER] for more
See page 4–24.
 OFFLINE O/C
 [ENTER] for more
See page 4–24.
 INADVERTENT ENERG.
 [ENTER] for more
See page 4–25.
 PHASE OVERCURRENT
 [ENTER] for more
See page 4–26.
 NEGATIVE SEQUENCE
 [ENTER] for more
See page 4–27.
 GROUND O/C
 [ENTER] for more
See page 4–29.
 PHASE DIFFERENTIAL
 [ENTER] for more
See page 4–30.
 GROUND DIRECTIONAL
 [ENTER] for more
See page 4–31.
 HIGH-SET PHASE O/C
 [ENTER] for more
See page 4–32.
 UNDERVOLTAGE
 [ENTER] for more
See page 4–33.
 OVERVOLTAGE
 [ENTER] for more
See page 4–34.
 VOLTS/HERTZ
 [ENTER] for more
See page 4–35.
 PHASE REVERSAL
 [ENTER] for more
See page 4–36.
 UNDERFREQUENCY
 [ENTER] for more
See page 4–37.
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ENTER
ð
ESCAPE
ð
 S4 SETPOINTS
 OUTPUT RELAYS
ESCAPE
ESCAPE
MESSAGE
ENTER
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
 S6 SETPOINTS
 VOLTAGE ELEMENTS
ð
4
 S5 SETPOINTS
 CURRENT RELAYS
ENTER
ESCAPE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
4-2
ð
489 Generator Management Relay
GE Multilin
4 SETPOINTS
4.1 OVERVIEW
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
 OVERFREQUENCY
 [ENTER] for more
See page 4–38.
 NEUTRAL OV (Fund)
 [ENTER] for more
See page 4–39.
 NEUTRAL OV (3rd)
 [ENTER] for more
See page 4–40.
 LOSS OF EXCITATION
 [ENTER] for more
See page 4–42.
 DISTANCE ELEMENT
 [ENTER] for more
See page 4–43.
 REACTIVE POWER
 [ENTER] for more
See page 4–46.
 REVERSE POWER
 [ENTER] for more
See page 4–47.
 LOW FORWARD POWER
 [ENTER] for more
See page 4–48.
 RTD TYPES
 [ENTER] for more
See page 4–49.
 RTD #1
 [ENTER] for more
See page 4–50.
ESCAPE
MESSAGE
ð
 S7 SETPOINTS
 POWER ELEMENTS
ENTER
ð
ESCAPE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
4
ESCAPE
MESSAGE
ð
 S8 SETPOINTS
 RTD TEMPERATURE
ENTER
ð
ESCAPE
ESCAPE
MESSAGE
↓
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
 RTD #12
 [ENTER] for more
See page 4–53.
 OPEN RTD SENSOR
 [ENTER] for more
See page 4–54.
 RTD SHORT/LOW TEMP
 [ENTER] for more
See page 4–54.
 MODEL SETUP
 [ENTER] for more
See page 4–56.
 THERMAL ELEMENTS
 [ENTER] for more
See page 4–68.
 TRIP COUNTER
 [ENTER] for more
See page 4–69.
 BREAKER FAILURE
 [ENTER] for more
See page 4–69.
 TRIP COIL MONITOR
 [ENTER] for more
See page 4–70.
ESCAPE
MESSAGE
ð
 S9 SETPOINTS
 THERMAL MODEL
ENTER
ð
ESCAPE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ð
 S10 SETPOINTS
 MONITORING
ENTER
ESCAPE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
GE Multilin
ð
489 Generator Management Relay
4-3
4.1 OVERVIEW
4 SETPOINTS
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
See page 4–71.
 CURRENT DEMAND
 [ENTER] for more
See page 4–72.
 MW DEMAND
 [ENTER] for more
See page 4–72.
 Mvar DEMAND
 [ENTER] for more
See page 4–72.
 MVA DEMAND
 [ENTER] for more
See page 4–72.
 PULSE OUTPUT
 [ENTER] for more
See page 4–74.
 RUNNING HOUR SETUP
 [ENTER] for more
See page 4–74.
 ANALOG OUTPUT 1
 [ENTER] for more
See page 4–75.
ESCAPE
MESSAGE
 S11 SETPOINTS
 ANALOG I/O
ð
ENTER
ð
ESCAPE
↓
 ANALOG OUTPUT 4
 [ENTER] for more
ESCAPE
MESSAGE
 ANALOG INPUT 1
 [ENTER] for more
ESCAPE
MESSAGE
See page 4–76.
↓
 ANALOG INPUT 4
 [ENTER] for more
ESCAPE
MESSAGE
ESCAPE
MESSAGE
 S12 SETPOINTS
 489 TESTING
ð
4
 VT FUSE FAILURE
 [ENTER] for more
ENTER
ESCAPE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
4-4
ð
 SIMULATION MODE
 [ENTER] for more
See page 4–78.
 PRE-FAULT SETUP
 [ENTER] for more
See page 4–79.
 FAULT SETUP
 [ENTER] for more
See page 4–80.
 TEST OUTPUT RELAYS
 [ENTER] for more
See page 4–81.
 TEST ANALOG OUTPUT
 [ENTER] for more
See page 4–81.
 COMM PORT MONITOR
 [ENTER] for more
See page 4–82.
 FACTORY SERVICE
 [ENTER] for more
See page 4–82.
489 Generator Management Relay
GE Multilin
4 SETPOINTS
4.1 OVERVIEW
4.1.2 TRIPS / ALARMS/ CONTROL FEATURES
The 489 Generator Management Relay has three basic function categories: TRIPS, ALARMS, and CONTROL.
a) TRIPS
A 489 trip feature may be assigned to any combination of the four output relays: R1 Trip, R2 Auxiliary, R3 Auxiliary, and R4
Auxiliary. If a Trip becomes active, the appropriate LED (indicator) on the 489 faceplate illuminates to indicate which output
relay has operated. Each trip feature may be programmed as latched or unlatched. Once a latched trip feature becomes
active, the RESET key must be pressed to reset that trip. If the condition that caused the trip is still present (for example, hot
RTD) the trip relay(s) will not reset until the condition disappears. On the other hand, if an unlatched trip feature becomes
active, that trip resets itself (and associated output relay(s)) after the condition that caused the trip ceases and the Breaker
Status input indicates that the breaker is open. If there is a lockout time, the trip relay(s) will not reset until the lockout time
has expired. Immediately prior to issuing a trip, the 489 takes a snapshot of generator parameters and stores them as pretrip values, allowing for troubleshooting after the trip. The cause of last trip message is updated with the current trip and the
489 display defaults to that message. All trip features are automatically logged and date and time stamped as they occur. In
addition, all trips are counted and logged as statistics such that any long term trends may be identified.
Note that a lockout time will occur due to overload trip (see Section 4.10.2: Model Setup on page 4–56 for details).
b) ALARMS
A 489 alarm feature may be assigned to operate any combination of four output relays: R5 Alarm, R4 Auxiliary, R3 Auxiliary, and R2 Auxiliary. When an Alarm becomes active, the appropriate LED (indicator) on the 489 faceplate will illuminate
when an output relay(s) has operated. Each alarm feature may be programmed as latched or unlatched. Once a latched
alarm feature becomes active, the reset key must be pressed to reset that alarm. If the condition that has caused the alarm
is still present (for example, hot RTD) the Alarm relay(s) will not reset until the condition is no longer present. If on the other
hand, an unlatched alarm feature becomes active, that alarm will reset itself (and associated output relay(s)) as soon as the
condition that caused the alarm ceases. As soon as an alarm occurs, the alarms messages are updated to reflect the alarm
and the 489 display defaults to that message. Since it may not be desirable to log all alarms as events, each alarm feature
may be programmed to log as an event or not. If an alarm is programmed to log as an event, when it becomes active, it is
automatically logged as a date and time stamped event.
c) CONTROL
A 489 control feature may be assigned to operate any combination of five output relays: R5 Alarm, R4 Auxiliary, R3 Auxiliary, and R2 Auxiliary, and R1 Trip. The combination of relays available for each function is determined by the suitability of
each relay for that particular function. The appropriate LED (indicator) on the 489 faceplate will illuminate when an output
relay(s) has been operated by a control function. Since it may not be desirable to log all control function as events, each
control feature may be programmed to log as an event or not. If a control feature is programmed to log as an event, each
control relay event is automatically logged with a date and time stamp.
4.1.3 RELAY ASSIGNMENT PRACTICES
There are six output relays. Five of the relays are always non-failsafe, the other (Service) is failsafe and dedicated to
annunciate internal 489 faults (these faults include setpoint corruption, failed hardware components, loss of control power,
etc.). The five remaining relays may be programmed for different types of features depending on what is required. One of
the relays, R1 Trip, is intended to be used as a trip relay wired to the unit trip breaker. Another relay, R5 Alarm, is intended
to be used as the main alarm relay. The three remaining relays, R2 Auxiliary, R3 Auxiliary, and R4 Auxiliary, are intended
for special requirements.
When assigning features to R2, R3, and R4 it is a good idea to decide early on what is required since features that may be
assigned may conflict. For example, if R2 is to be dedicated as a relay for sequential tripping, it cannot also be used to
annunciate a specific alarm condition.
In order to ensure that conflicts in relay assignments do not occur, several precautions have been taken. All trips default to
the R1 Trip output relay and all alarms default to the R5 Alarm relay. It is recommended that relay assignments be reviewed
once all the setpoints have been programmed.
GE Multilin
489 Generator Management Relay
4-5
4
4.1 OVERVIEW
4 SETPOINTS
4.1.4 DUAL SETPOINTS
The 489 has dual settings for the current, voltage, power, RTD, and thermal model protection elements (setpoints pages S5
to S9). These setpoints are organized in two groups: the main group (Group 1) and the alternate group (Group 2). Only one
group of settings is active in the protection scheme at a time. The active group can be selected using the ACTIVATE SETPOINT GROUP setpoint or an assigned digital input in the S3 Digital Inputs setpoints page. The LED indicator on the faceplate of the 489 will indicate when the alternate setpoints are active in the protection scheme. Independently, the setpoints
in either group can be viewed and/or edited using the EDIT SETPOINT GROUP setpoint. Headers for each setpoint message
subgroup that has dual settings will be denoted by a superscript number indicating which setpoint group is being viewed or
edited. Also, when a setpoint that has dual settings is stored, the flash message that appears will indicate which setpoint
group setting has been changed.
If only one setting group is required, edit and activate only Group 1 (that is, do not assign a digital input to Dual Setpoints,
and do not alter the ACTIVATE SETPOINT GROUP setpoint or EDIT SETPOINT GROUP setpoint in S3 DIGITAL INPUTS).
4.1.5 COMMISSIONING
4
Tables for recording of 489 programmed setpoints are available as a Microsoft Word document from the GE Multilin website
at http://www.GEindustrial.com/multilin. See the Support Documents section of the 489 Generator Management Relay
page for the latest version. This document is also available in print from the GE Multilin literature department (request publication number GET-8445).
4-6
489 Generator Management Relay
GE Multilin
4 SETPOINTS
4.2 S1 489 SETUP
4.2S1 489 SETUP
4.2.1 PASSCODE
PATH: SETPOINTS  S1 489 SETUP  PASSCODE
ð
 PASSCODE
 [ENTER] for more
ð ENTER PASSCODE FOR
ESCAPE
ACCESS:
Range: 1 to 8 numeric digits. Seen only if passcode is not
"0" and SETPOINT ACCESS is "Restricted".
ESCAPE
SETPOINT ACCESS:
Permitted
Range: Permitted, Restricted. Seen only if the passcode
is "0" or SETPOINT ACCESS is "Permitted".
CHANGE PASSCODE:
No
Range: No, Yes. Seen only if the passcode is "0" or
SETPOINT ACCESS is "Permitted".
ENTER
MESSAGE
ESCAPE
MESSAGE
A passcode access security feature is provided with the 489. The passcode is defaulted to "0" (without the quotes) at the
time of shipping. Passcode protection is ignored when the passcode is "0". In this case, the setpoint access jumper is the
only protection when programming setpoints from the front panel keypad and setpoints may be altered using the RS232
and RS485 serial ports without access protection. If however, the passcode is changed to a non-zero value, passcode protection is enabled. The access jumper must be installed and the passcode must be entered, to program setpoints from the
front panel keypad. The passcode must also be entered individually from each serial communications port to gain setpoint
programming access from that port.
To enable passcode protection on a new relay, follow the procedure below:
Press
2.
Select "Yes" and follow directions to enter a new passcode 1 to 8 digits in length.
3.
Once a new passcode (other than 0) is programmed, it must be entered to gain setpoint access whenever setpoint
access is restricted. Assuming that a non-zero passcode has been programmed and setpoint access is restricted, then
selecting the passcode subgroup causes the ENTER PASSCODE AGAIN message to appear.
4.
Enter the correct passcode. A flash message will advise if the code is incorrect and allow a retry. If it is correct and the
setpoint access jumper is installed, the SETPOINT ACCESS: Permitted message appears.
5.
Setpoints can now be entered. Exit the passcode message with the ESCAPE key and program the appropriate setpoints.
If no keypress occurs for 5 minutes, access will be disabled and the passcode must be re-entered. Removing the setpoint access jumper or setting SETPOINT ACCESS to "Restricted" also disables setpoint access immediately.
ENTER
then
until the CHANGE PASSCODE message is displayed.
1.
MESSAGE
If a new passcode is required, gain setpoint access by entering the current valid passcode. Press MESSAGE
to display the
CHANGE PASSCODE message and follow the directions. If an invalid passcode is entered, the encrypted passcode is viewable by pressing HELP . Consult GE Multilin with this number if the currently programmed passcode is unknown. The passcode can be determined with deciphering software.
4.2.2 PREFERENCES
PATH: SETPOINTS  S1 489 SETUP  PREFERENCES
ð
 PREFERENCES
 [ENTER] for more
ENTER
Range: 0.5 to 10.0 s in steps of 1
CYCLE TIME: 2.0 s
ESCAPE
DEFAULT MESSAGE
TIMEOUT: 300 s
Range: 10 to 900 s in steps of 1
PARAMETER AVERAGES
CALC. PERIOD: 15 min
Range: 1 to 90 min. in steps of 1
TEMPERATURE DISPLAY:
Celsius
Range: Celsius, Fahrenheit
WAVEFORM TRIGGER
POSITION: 25%
Range: 1 to 100% in steps of 1
WAVEFORM MEM BUFFER
8x14 CYCLES
Range: 1x64, 2x42, 3x32, 4x35, 5x21, 6x18, 7x16, 8x14,
9x12, 10x11, 11x10, 12x9, 13x9, 14x8, 15x8,
16x7 cycles
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
GE Multilin
ð DEFAULT MESSAGE
ESCAPE
489 Generator Management Relay
4-7
4
4.2 S1 489 SETUP
4 SETPOINTS
Some of the 489 characteristics can be modified to suit different situations. Normally the S1 489 SETUP  PREFERENCES setpoints group will not require any changes.
•
DEFAULT MESSAGE CYCLE TIME: If multiple default messages are chosen, the display automatically cycles
through these messages. The messages display time can be changed to accommodate different reading rates.
•
DEFAULT MESSAGE TIMEOUT: If no keys are pressed for a period of time then the relay automatically scans through
a programmed set of default messages. This time can be modified to ensure messages remain on the screen long
enough during programming or reading of actual values.
•
PARAMETER AVERAGES CALCULATION PERIOD: The period of time over which the parameter averages are calculated may be adjusted with this setpoint. The calculation is a sliding window.
•
TEMPERATURE DISPLAY: Measurements of temperature may be displayed in either Celsius or Fahrenheit. Each
actual value temperature message will be denoted by either °C for Celsius or °F for Fahrenheit. RTD setpoints are
always displayed in Celsius.
•
WAVEFORM TRIGGER: The trigger setpoint allows the user to adjust how many pre-trip and post-trip cycles are
stored in the waveform memory when a trip occurs. A value of 25%, for example, when the WAVEFORM MEMORY BUFFER is "7 x 16" cycles, would produce a waveform of 4 pre-trip cycles and 12 post-trip cycles.
•
WAVEFORM MEMORY BUFFER: Selects the partitioning of the waveform memory. The first number indicates the
number of events and the second number, the number of cycles. The relay captures 12 samples per cycle. When more
waveform captures occur than the available storage, the oldest data will be discarded.
4
4.2.3 SERIAL PORTS
PATH: SETPOINTS  S1 489 PREFERENCES  SERIAL PORTS
ð
 SERIAL PORTS
[ENTER] for more
ENTER
ð SLAVE ADDRESS:
Range: 1 to 254 in steps of 1
ESCAPE
254
ESCAPE
COMPUTER RS485
BAUD RATE: 9600
Range: 300, 1200, 2400, 4800, 9600, 19200
COMPUTER RS485
PARITY: None
Range: None, Odd, Even
AUXILIARY RS485
BAUD RATE: 9600
Range: 300, 1200, 2400, 4800, 9600, 19200
AUXILIARY RS485
PARITY: None
Range: None, Odd, Even
PORT USED FOR DNP:
None
Range: None, Computer RS485, Auxiliary RS485,
Front Panel RS232
DNP SLAVE ADDRESS:
255
Range: 0 to 255 in steps of 1
DNP TURNAROUND
TIME: 10 ms
Range: 0 to 100 ms in steps of 10
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
The 489 is equipped with 3 independent serial communications ports supporting a subset of Modbus RTU protocol. The
front panel RS232 has a fixed baud rate of 9600 and a fixed data frame of 1 start/8 data/1stop/no parity. The front port is
intended for local use only and will respond regardless of the slave address programmed. The front panel RS232 program
port may be connected to a personal computer running the 489PC software. This program may be used for downloading
and uploading setpoint files, viewing measured parameters, and upgrading the 489 firmware to the latest revision.
For RS485 communications, each relay must have a unique address from 1 to 254. Address 0 is the broadcast address
monitored by all relays. Addresses do not have to be sequential but no two units can have the same address or errors will
occur. Generally, each unit added to the link will use the next higher address starting at 1. Baud rates can be selected as
300, 1200, 2400, 4800, 9600, or 19200. The data frame is fixed at 1 start, 8 data, and 1 stop bits, while parity is optional.
The computer RS485 port is a general purpose port for connection to a DCS, PLC, or PC. The Auxiliary RS485 port may
also be used as another general purpose port or it may be used to talk to Auxiliary GE Multilin devices in the future.
4-8
489 Generator Management Relay
GE Multilin
4 SETPOINTS
4.2 S1 489 SETUP
4.2.4 REAL TIME CLOCK
PATH: SETPOINTS  S1 489 SETUP  REAL TIME CLOCK
ð
 REAL TIME CLOCK
 [ENTER] for more
ENTER
Range: 01/01/1995 to 12/31/2094
ð DATE (MM, DD, YYYY):
ESCAPE
01/01/1995
ESCAPE
TIME (HH.MM.SS):
12:00:00
Range: 00:00:00 to 23:59:59
IRIG-B SIGNAL TYPE:
NONE
Range: None, DC Shift, Amplitude Modulated
MESSAGE
ESCAPE
MESSAGE
For events that are recorded by the event recorder to be correctly time/date stamped, the correct time and date must be
entered. A battery backed internal clock runs continuously even when power is off. It has the same accuracy as an electronic watch approximately ±1 minute per month. It must be periodically corrected either manually through the front panel or
via the clock update command over the RS485 serial link. If the approximate time an event occurred without synchronization to other relays is sufficient, then entry of time/date from the front panel keys is adequate.
If the RS485 serial communication link is used then all the relays can keep time in synchronization with each other. A new
clock time is pre-loaded into the memory map via the RS485 communications port by a remote computer to each relay connected on the communications channel. The computer broadcasts (address 0) a "set clock" command to all relays. Then all
relays in the system begin timing at the exact same instant. There can be up to 100 ms of delay in receiving serial commands so the clock time in each relay is ±100 ms, ± the absolute clock accuracy in the PLC or PC. See the chapter on
Communications for information on programming the time preload and synchronizing commands.
An IRIG-B signal receiver may be connected to 489 units with hardware revision G or higher. The relay will continuously
decode the time signal and set its internal time correspondingly. The “signal type” setpoint must be set to match the signal
provided by the receiver.
4.2.5 DEFAULT MESSAGES
PATH: SETPOINTS  S1 489 SETUP  DEFAULT MESSAGES
ð
 DEFAULT MESSAGES
 [ENTER] for more
ENTER
N/A
0
Range:
N/A
0
Range:
N/A
FREQUENCY:
0.00 Hz
Range:
N/A
POWER FACTOR:
0.00
Range:
N/A
REAL POWER:
0 MW
Range:
N/A
REACTIVE POWER
0 Mvar
Range:
N/A
DATE: 01/01/1995
TIME: 12:00:00
Range:
N/A
GE MULTILIN
489 GENERATOR RELAY
Range:
N/A
Stopped
ESCAPE
A:
C:
0
0
B:
Amps
Vab:
Vca:
0
0
Vbc:
Volts
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
GE Multilin
Range:
ð GENERATOR STATUS:
ESCAPE
489 Generator Management Relay
4-9
4
4.2 S1 489 SETUP
4 SETPOINTS
The 489 displays default messages after a period of keypad inactivity. Up to 20 default messages can be selected for display. If more than one message is chosen, they will automatically scroll at a rate determined by the S1 489 SETUP  PREFERENCES  DEFAULT MESSAGE CYCLE TIME setpoint. Any actual value can be selected for display. In addition, up to 5 userprogrammable messages can be created and displayed with the message scratchpad. For example, the relay could be set
to alternately scan a generator identification message, the current in each phase, and the hottest stator RTD. Currently
selected default messages can be viewed in DEFAULT MESSAGES subgroup.
Default messages can be added to the end of the default message list, as follows:
Enter the correct passcode at S1 489 SETUP  PASSCODE  ENTER PASSCODE FOR ACCESS to allow setpoint entry
(unless it has already been entered or is "0", defeating the passcode security feature).
2.
Select the message to be add to the default message list using the
sage can be any Actual Value or Message Scratchpad message.
3.
Press
ENTER
4.
Press
ENTER
5.
If the procedure was followed correctly, the DEFAULT MESSAGE HAS BEEN ADDED flash message is displayed:
6.
To verify that the message was added, view the last message under the S1 489 SETUP  DEFAULT MESSAGES menu.
MESSAGE
and
MESSAGE
keys. The selected mes-
. The PRESS [ENTER] TO ADD DEFAULT MESSAGES message will be displayed for 5 seconds:
again while this message is displayed to add the current message to the end of the default message list.
Default messages can be removed from the default message list, as follows:
1.
Enter the correct passcode at S1 489 SETUP  PASSCODE  ENTER PASSCODE FOR ACCESS to allow setpoint entry
(unless the passcode has already been entered or unless the passcode is "0" defeating the passcode security feature).
2.
Select the message to remove from the default message list under the S1 489 SETUP  DEFAULT MESSAGES menu.
3.
Select the default message to remove and press
4.
Press
5.
If the procedure was followed correctly, the DEFAULT MESSAGE HAS BEEN REVOVED flash message is displayed.
ENTER
ENTER
. The relay will display PRESS [ENTER] TO REMOVE MESSAGE.
while this message is displayed to remove the current message out of the default message list.
4.2.6 MESSAGE SCRATCHPAD
PATH: SETPOINTS  S1 489 SETUP  MESSAGE SCRATCHPAD
 MESSAGE SCRATCHPAD
 [ENTER] for more
ð
4
1.
ENTER
ð TEXT 1
Range: 40 alphanumeric characters
TEXT 2
Range: 40 alphanumeric characters
TEXT 3
Range: 40 alphanumeric characters
TEXT 4
Range: 40 alphanumeric characters
GE MULTILIN
489 GENERATOR RELAY
Range: 40 alphanumeric characters
ESCAPE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
Up to 5 message screens can be programmed under the Message Scratchpad area. These messages may be notes that
pertain to the installation of the generator. In addition, these notes may be selected for scanning during default message
display. This might be useful for reminding operators to perform certain tasks. The messages may be entered from the
communications ports or through the keypad. To enter a 40 character message:
1.
Select the user message to be changed.
2.
Press the decimal [.] key to enter text mode. An underscore cursor will appear under the first character.
3.
Use the
4.
Press the [.] key to advance to the next character. To skip over a character press the [.] key. If an incorrect character is
accidentally stored, press the [.] key enough times to scroll the cursor around to the character.
5.
When the desired message is displayed press the ENTER key to store or the
permanently stored. Press ESCAPE to cancel the altered message.
4-10
VALUE
and
VALUE
keys to display the desired character. A space is selected like a character.
489 Generator Management Relay
ESCAPE
key to abort. The message is now
GE Multilin
4 SETPOINTS
4.2 S1 489 SETUP
4.2.7 CLEAR DATA
PATH: SETPOINTS  S1 489 SETUP  CLEAR DATA
ð
 CLEAR DATA
 [ENTER] for more
ENTER
ð CLEAR LAST TRIP
Range: No, Yes
ESCAPE
DATA: No
ESCAPE
RESET MWh and Mvarh
METERS: No
Range: No, Yes
CLEAR PEAK DEMAND
DATA: No
Range: No, Yes
CLEAR RTD
MAXIMUMS: No
Range: No, Yes
CLEAR ANALOG I/P
MIN/MAX: No
Range: No, Yes
CLEAR TRIP
COUNTERS: No
Range: No, Yes
CLEAR EVENT
RECORD: No
Range: No, Yes
CLEAR GENERATOR
INFORMATION: No
Range: No, Yes
CLEAR BREAKER
INFORMATION: No
Range: No, Yes
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
4
These commands may be used to clear various historical data.
•
CLEAR LAST TRIP DATA: The Last Trip Data may be cleared by executing this command.
•
CLEAR MWh and Mvarh METERS: Executing this command will clear the MWh and Mvarh metering to zero.
•
CLEAR PEAK DEMAND DATA: Execute this command to clear peak demand values.
•
CLEAR RTD MAXIMUMS: All maximum RTD temperature measurements are stored and updated each time a new
maximum temperature is established. Execute this command to clear the maximum values.
•
CLEAR ANALOG I/P MIN/MAX: The minimum and maximum analog input values are stored for each Analog Input.
Those minimum and maximum values may be cleared at any time.
•
CLEAR TRIP COUNTERS: There are counters for each possible type of trip. Those counters may be cleared by executing this command.
•
CLEAR EVENT RECORD: The event recorder saves the last 40 events, automatically overwriting the oldest event. If
desired, all events can be cleared using this command to prevent confusion with old information.
•
CLEAR GENERATOR INFORMATION: The number of thermal resets and the total generator running hours can be
viewed in actual values. On a new installation, or if new equipment is installed, this information is cleared through this
setpoint.
•
CLEAR BREAKER INFORMATION: The total number of breaker operations can be viewed in actual values. On a new
installation or if maintenance work is done on the breaker, this accumulator can be cleared with this setpoint.
GE Multilin
489 Generator Management Relay
4-11
4.3 S2 SYSTEM SETUP
4 SETPOINTS
4.3S2 SYSTEM SETUP
4.3.1 CURRENT SENSING
PATH: SETPOINTS  S2 SYSTEM SETUP  CURRENT SENSING
ð
 CURRENT SENSING
 [ENTER] for more
ENTER
Range: 1 to 5000 step 1, Not Programmed
-------------
ESCAPE
GROUND CT:
50:0.025
Range: None, 1A Secondary, 5A Secondary, 50:0.025
GROUND CT RATIO:
100: 1
Range: 10 to 10000 in steps of 1
Message seen only if Ground CT Type is 1 A
GROUND CT RATIO:
100: 5
Range: 10 to 10000 in steps of 1
Message seen only if Ground CT Type is 5 A
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
As a safeguard, the PHASE CT PRIMARY and GENERATOR PARAMETERS setpoints are defaulted to "--------" when shipped,
indicating that the 489 was never programmed. Once these values are entered, the 489 will be in service. Select the Phase
CT so that the maximum fault current does not exceed 20 times the primary rating. When relaying class CTs are purchased, this precaution helps prevent CT saturation under fault conditions. The secondary value of 1 or 5 A must be specified when ordering so the proper hardware will be installed. The PHASE CT PRIMARY setpoint applies to both the neutral end
CTs as well as the output CTs.
For high resistance grounded systems, sensitive ground current detection is possible if the 50:0.025 Ground CT is used. To
use the 50:0.025 CT input, set GROUND CT to "50:0.025". No additional ground CT messages will appear. On solid or low
resistance grounded systems, where fault currents may be quite large, the 489 1 A/5 A secondary Ground CT input should
be used. Select the Ground CT primary so that potential fault current does not exceed 20 times the primary rating. When
relaying class CTs are purchased, this precaution will ensure that the Ground CT does not saturate under fault conditions.
The 489 uses a nominal CT primary rating of 5 A for calculation of pickup levels.
4.3.2 VOLTAGE SENSING
PATH: SETPOINTS  S2 SYSTEM SETUP  VOLTAGE SENSING
 VOLTAGE SENSING
 [ENTER] for more
ð
4
ð PHASE CT PRIMARY:
ESCAPE
ENTER
ð VT CONNECTION TYPE:
Range: Open Delta, Wye, None
ESCAPE
None
ESCAPE
VOLTAGE TRANSFORMER
RATIO: 5.00:1
Range: 1.00:1 to 300.00:1 in steps of 0.01
NEUTRAL VOLTAGE
TRANSFORMER: No
Range: No, Yes
NEUTRAL VT
RATIO: 5.00:1
Range: 1.00:1 to 240.00:1 in steps of 0.01. Seen only if
NEUTRAL VOLTAGE TRANSFORMER is "Yes"
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
The voltage transformer connections and turns ratio are entered here. The VT should be selected such that the secondary
phase-phase voltage of the VTs is between 70.0 and 135.0 V when the primary is at generator rated voltage.
The Neutral VT ratio must be entered here for voltage measurement across the neutral grounding device. Note that the
neutral VT input is not intended to be used at continuous voltages greater than 240 V. If the voltage across the neutral input
is less than 240 V during fault conditions, an auxiliary voltage transformer is not required. If this is not the case, use an auxiliary VT to drop the fault voltage below 240 V. The NEUTRAL VT RATIO entered must be the total effective ratio of the grounding transformer and any auxiliary step up or step down VT.
For example, if the distribution transformer ratio is 13200:480 and the auxiliary VT ratio is 600:120, the NEUTRAL VT RATIO
setpoint is calculated as:
NEUTRAL VT RATIO
= Distribution Transformer Ratio × Auxiliary VT Ratio : 1
13200 600
= ---------------- × ---------- : 1 = 137.50 : 1
480
120
(EQ 4.1)
Therefore, set NEUTRAL VT RATIO to 137.50:1
4-12
489 Generator Management Relay
GE Multilin
4 SETPOINTS
4.3 S2 SYSTEM SETUP
4.3.3 GENERATOR PARAMETERS
PATH: SETPOINTS  S2 SYSTEM SETUP  GENERATOR PARAMETERS
 GEN. PARAMETERS
 [ENTER] for more
ESCAPE
MVA: ----------------
Range: 0.050 to 2000.000 MVA
“----------” indicates Not Programmed
ESCAPE
GENERATOR RATED
POWER FACTOR: -------
Range: 0.05 to 0.99, 1.00
“----------” indicates Not Programmed
GENERATOR VOLTAGE
PHASE-PHASE: --------
Range: 100 to 30000 V in steps of 1
“----------” indicates Not Programmed
GENERATOR NORMAL
FREQUENCY: ----------
Range: 25 Hz, 50 Hz, 60 Hz
“----------” indicates Not Programmed
GENERATOR PHASE
SEQUENCE: -----------
Range: ABC, ACB
“----------” indicates Not Programmed
ENTER
ð
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ð GENERATOR RATED
As a safeguard, when a unit is received from the factory, the PHASE CT PRIMARY and Generator Parameters setpoints will be
defaulted to "--------", indicating they are not programmed. The 489 indicates that it was never programmed. Once these
values are entered, the 489 will be in service. All elements associated with power quantities are programmed in per unit values calculated from the rated MVA and power factor. The generator full load amps (FLA) is calculated as
Generator Rated MVA
Generator FLA = ---------------------------------------------------------------------------------------------------------------------3 × Generator Rated Phase-Phase Voltage
(EQ 4.2)
All voltage protection features that require a level setpoint are programmed in per unit of the rated generator phase-phase
voltage.The nominal system frequency must be entered here. This setpoint allows the 489 to determine the internal sampling rate for maximum accuracy. If the sequence of phase rotation for a given system is ACB rather than the standard
ABC, the system phase sequence setpoint may be used to accommodate this rotation. This setpoint allows the 489 to properly calculate phase reversal and negative sequence quantities.
4.3.4 SERIAL START/STOP INITIATION
PATH: SETPOINTS  S2 SYSTEM SETUP  SERIAL START/STOP
ð
 SERIAL START/STOP
 [ENTER] for more
ENTER
ð SERIAL START/STOP
Range: On, Off
ESCAPE
INITIATION: Off
ESCAPE
STARTUP INITIATION
RELAYS (2-5): ----
Range: Any Combination of Relays 2 to 5
SHUTDOWN INITIATION
RELAYS (1-4): ----
Range: Any Combination of Relays 1 to 4
SERIAL START/STOP
EVENTS: Off
Range: On, Off
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
If enabled, this feature will allow the user to initiate a generator startup or shutdown via the RS232/RS485 communication
ports. Refer to the Communications chapter for command formats. When a startup command is issued, the auxiliary
relay(s) assigned for starting control will be activated for 1 second to initiate startup. When a stop command is issued, the
assigned relay(s) will be activated for 1 second to initiate a shutdown.
GE Multilin
489 Generator Management Relay
4-13
4
4.4 S3 DIGITAL INPUTS
4 SETPOINTS
4.4S3 DIGITAL INPUTS
4.4.1 DESCRIPTION
The 489 has nine (9) digital inputs for use with external contacts. Two of the 489 digital inputs have been pre-assigned as
inputs having a specific function. The Access Switch does not have any setpoint messages associated with it. The Breaker
Status input, may be configured for either an 'a' or 'b' auxiliary contact. The remaining seven digital inputs are assignable;
that is to say, each input may be assigned to any of a number of different functions. Some of those functions are very specific, others may be programmed to adapt to user requirements.
WARNING
Terminals C1 and C2 must be shorted to allow changing of any setpoint values from the front panel keypad. This
safeguard is in addition to the setpoint passcode feature, which functions independently (see the S1 489 SETUP 
PASSCODE menu). The access switch has no effect on setpoint programming from the RS232 and RS485 serial
communications ports.
4.4.2 BREAKER STATUS
PATH: SETPOINTS  S3 DIGITAL INPUTS  BREAKER STATUS
ð
 BREAKER STATUS
 [ENTER] for more
ENTER
ESCAPE
ð BREAKER STATUS:
Breaker Auxiliary b
Range: Breaker Auxiliary a,
Breaker Auxiliary b
4
This input is necessary for all installations. The 489 determines when the generator is online or offline based on the
Breaker Status input. Once 'Breaker Auxiliary a' is chosen, terminals C3 and C4 will be monitored to detect the state of the
machine main breaker, open signifying the breaker is open and shorted signifying the breaker is closed. Once "Breaker
Auxiliary b" is chosen, terminals C3 and C4 will be monitored to detect the state of the breaker, shorted signifying the
breaker is open and open signifying the breaker is closed.
4-14
489 Generator Management Relay
GE Multilin
4 SETPOINTS
4.4 S3 DIGITAL INPUTS
4.4.3 GENERAL INPUT A TO G
PATH: SETPOINTS  S3 DIGITAL INPUTS  GENERAL INPUT A(G)
ð
 GENERAL INPUT A
 [ENTER] for more
ENTER
ð ASSIGN DIGITAL
Range: None, Input 1 to Input 7. If an input is assigned to
the Tachometer function, it may not be used here
ESCAPE
INPUT: None
ESCAPE
ASSERTED DIGITAL
INPUT STATE: Closed
Range: Closed, Open
INPUT NAME:
Input A
Range: 12 alphanumeric characters
BLOCK INPUT
FROM ONLINE: 0 s
Range: 0 to 5000 in steps of 1. "0" indicates feature is
active while generator is offline as well as online.
GENERAL INPUT A
CONTROL: Off
Range: Off, On
PULSED CONTROL RELAY
DWELL TIME: 0.0 s
Range: 0.0 to 25.0 s in steps of 0.1
ASSIGN CONTROL
RELAYS (1-5): -----
Range: Any combination of Relays 1 to 5
GENERAL INPUT A
CONTROL EVENTS: Off
Range: Off, On
GENERAL INPUT A
ALARM: Off
Range: Off, Latched, Unlatched
ASSIGN ALARM
RELAYS (2-5): ---5
Range: Any combination of Relays 2 to 5
GENERAL INPUT A
ALARM DELAY: 0.5 s
Range: 0.1 to 2100.0 s in steps of 0.1
GENERAL INPUT A
ALARM EVENTS: Off
Range: Off, On
GENERAL INPUT A
TRIP: Off
Range: Off, Latched, Unlatched
ASSIGN TRIP
RELAYS (1-4): 1---
Range: Any combination of Relays 1 to 4
GENERAL INPUT A
TRIP DELAY: 5.0 s
Range: 0.1 to 2100.0 s in steps of 0.1
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
4
The SR489 relay can be programmed to delay beyond 2100.0 seconds but the response time is not guaranteed.
NOTE
The seven General Input functions are flexible enough to meet most of the desired digital input requirements. The asserted
state and the name of the digital inputs are programmable. To disable the input functions when the generator is offline, until
some time after the generator is brought online, a block time should be set. The input functions will be enabled once the
block delay has expired. A value of zero for the block time indicates that the input functions are always enabled.
Inputs may be configured for control, alarm, or trip. If the control feature is enabled, the assigned output relay(s) operate
when the input is asserted. If the PULSED CONTROL RELAY DWELL TIME is set to 0, the output relay(s) operate only while the
input is asserted. However, if a dwell time is assigned, the output relay(s) operate as soon as the input is asserted for a
period of time specified by the setpoint. If an alarm or trip is enabled and the input is asserted, an alarm or trip will occur
after the specified delay.
GE Multilin
489 Generator Management Relay
4-15
4.4 S3 DIGITAL INPUTS
4 SETPOINTS
4.4.4 REMOTE RESET
PATH: SETPOINTS  S3 DIGITAL INPUTS  REMOTE RESET
ð
 REMOTE RESET
 [ENTER] for more
ENTER
ESCAPE
ð ASSIGN DIGITAL
INPUT: None
Range: None, Input 1, Input 2, Input 3, Input 4, Input 5,
Input 6, Input 7
Once an input is assigned to the Remote Reset function, shorting that input will reset any latched trips or alarms that may
be active, provided that any thermal lockout time has expired and the condition that caused the alarm or trip is no longer
present.
If an input is assigned to the tachometer function, it may not be used here.
4.4.5 TEST INPUT
PATH: SETPOINTS  S3 DIGITAL INPUTS  TEST INPUT
ENTER
ESCAPE
ð ASSIGN DIGITAL
INPUT: None
Range: None, Input 1, Input 2, Input 3, Input 4, Input 5,
Input 6, Input 7
Once the 489 is in service, it may be tested from time to time as part of a regular maintenance schedule. The unit will have
accumulated statistical information relating historically to generator and breaker operation. This information includes: last
trip data, peak demand data, MWh and Mvarh metering, parameter averages, RTD maximums, analog input minimums and
maximums, number of trips, number of trips by type, number of breaker operations, the number of thermal resets, total generator running hours, and the event record. When the unit is under test and one of the inputs is assigned to the Test Input
function, shorting that input will prevent all of this data from being corrupted or updated.
If an input is assigned to the tachometer function, it may not be used here.
4.4.6 THERMAL RESET
PATH: SETPOINTS  S3 DIGITAL INPUTS  THERMAL RESET
 THERMAL RESET
 [ENTER] for more
ð
ENTER
ESCAPE
ð ASSIGN DIGITAL
INPUT: None
Range: None, Input 1, Input 2, Input 3, Input 4, Input 5,
Input 6, Input 7
During testing or in an emergency, it may be desirable to reset the thermal memory used to zero. If an input is assigned to
the Thermal Reset function, shorting that input will reset the thermal memory used to zero. All Thermal Resets will be
recorded as events.
If an input is assigned to the tachometer function, it may not be used here.
4.4.7 DUAL SETPOINTS
PATH: SETPOINTS  S3 DIGITAL INPUTS  DUAL SETPOINTS
 DUAL SETPOINTS
 [ENTER] for more
ð
4
ð
 TEST INPUT
 [ENTER] for more
ENTER
ð ASSIGN DIGITAL
Range: None, Input 1, Input 2, Input 3, Input 4, Input 5,
Input 6, Input 7
ESCAPE
INPUT: None
ESCAPE
ACTIVATE SETPOINT
GROUP: Group 1
Range: Group 1, Group 2
EDIT SETPOINT
GROUP: Group 1
Range: Group 1, Group 2
MESSAGE
ESCAPE
MESSAGE
If an input is assigned to the tachometer function, it may not be used here.
This feature allows for dual settings for the current, voltage, power, RTD, and thermal model protection elements (setpoint
pages S5 to S9). These settings are organized in two setpoint groups: the main group (Group 1) and the alternate group
(Group 2). Only one group of settings are active in the protection scheme at a time.
4-16
489 Generator Management Relay
GE Multilin
4 SETPOINTS
4.4 S3 DIGITAL INPUTS
The following chart illustrates the Group 2 (alternate group) setpoints
2 S5 SETPOINTS
CURRENT ELEMENTS
2 S6 SETPOINTS
VOLTAGE ELEMENTS
2 S7 SETPOINTS
POWER ELEMENTS
2 S8 SETPOINTS
RTD TEMPERATURE
2 S9 SETPOINTS
THERMAL MODEL
2 OVERCURRENT ALARM
2 UNDERVOLTAGE
2 REACTIVE POWER
2 RTD TYPES
2 MODEL SETUP
2 OFFLINE O/C
2 OVERVOLTAGE
2 REVERSE POWER
2 RTD #1
2 THERMAL ELEMENTS
2 INADVERTENT ENERG.
2 VOLTS/HERTZ
2 LOW FORWARD POWER
2 PHASE OVERCURRENT
2 PHASE REVERSAL
2 RTD #12
2 NEGATIVE SEQUENCE
2 UNDERFREQUENCY
2 OPEN RTD SENSOR
2 GROUND O/C
2 NEUTRAL O/V (Fund)
2 RTD SHORT/LOW TEMP
2 PHASE DIFFERENTIAL
2 NEUTRAL O/V (3rd)
2 GROUND DIRECTIONAL
2 LOSS OF EXCITATION
2 HIGH-SET PHASE O/C
2 DISTANCE ELEMENT
↓
The active group can be selected using the ACTIVATE SETPOINT GROUP setpoint or the assigned digital input (shorting that
input will activate the alternate set of protection setpoints, Group 2). In the event of a conflict between the ACTIVATE SETPOINT GROUP setpoint or the assigned digital input, Group 2 will be activated. The LED indicator on the faceplate of the 489
will indicate when the alternate setpoints are active in the protection scheme. Changing the active setpoint group will be
logged as an event. Independently, the setpoints in either group can be viewed and/or edited using the EDIT SETPOINT
GROUP setpoint. Headers for each setpoint message subgroup that has dual settings will be denoted by a superscript number indicating which setpoint group is being viewed or edited. Also, when a setpoint that has dual settings is stored, the
flash message that appears will indicate which setpoint group setting has been changed.
4.4.8 SEQUENTIAL TRIP
PATH: SETPOINTS  S3 DIGITAL INPUTS  SEQUENTIAL TRIP
ð
 SEQUENTIAL TRIP
 [ENTER] for more
ENTER
ð ASSIGN DIGITAL
Range: None, Input 1 to Input 7. If an input is assigned to
the Tachometer, it may not be used here.
ESCAPE
INPUT: None
ESCAPE
SEQUENTIAL TRIP TYPE
Low Forward Power
Range: Low Forward Power, Reverse Power
ASSIGN TRIP
RELAYS (1-4): 1---
Range: Any combination of Relays 1 to 4
SEQUENTIAL TRIP
LEVEL: 0.05 x Rated MW
Range: 0.02 to 0.99 × Rated MW in steps of 0.01
SEQUENTIAL TRIP
DELAY: 1.0 s
Range: 0.2 to 120.0 s in steps of 0.1
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
During routine shutdown and for some less critical trips, it may be desirable to use the sequential trip function to prevent
overspeed. If an input is assigned to the sequential trip function, shorting that input will enable either a low forward power or
reverse power function. Once the measured 3-phase total power falls below the low forward power level, or exceeds the
reverse power level for the period of time specified, a trip will occur. This time delay will typically be shorter than that used
for the standard reverse power or low forward power elements. The level is programmed in per unit of generator rated MW
calculated from the rated MVA and rated power factor. If the VT type is selected as None, the sequential trip element will
operate as a simple timer. Once the input has been shorted for the period of time specified by the delay, a trip will occur.
NOTE
The minimum magnitude of power measurement is determined by the phase CT minimum of 2% rated CT primary.
If the level for reverse power is set below that level, a trip or alarm will only occur once the phase current exceeds
the 2% cutoff.
Users are cautioned that a reverse power element may not provide reliable indication when set to a very low setting, particularly under conditions of large reactive loading on the generator. Under such conditions, low forward power is a more reliable element.
GE Multilin
489 Generator Management Relay
4-17
4
4.4 S3 DIGITAL INPUTS
4 SETPOINTS
4.4.9 FIELD-BREAKER DISCREPANCY
PATH: SETPOINTS  S3 DIGITAL INPUTS  FIELD-BKR DISCREP.
ð
 FIELD-BKR DISCREP.
 [ENTER] for more
ENTER
Range: None, Input 1 to Input 7. If an input is assigned to
the Tachometer, it may not be used here.
INPUT: None
ESCAPE
FIELD STATUS
CONTACT: Auxiliary a
Range: Auxiliary a, Auxiliary b
ASSIGN TRIP
RELAYS (1-4): 1---
Range: Any combination of Relays 1 to 4
FIELD-BKR DISCREP.
TRIP DELAY: 1.0 s
Range: 0.1 to 500.0 s in steps of 0.1
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
The field-breaker discrepancy function is intended for use with synchronous generators. If a digital input is assigned to this
function, any time the field status contact indicates the field is not applied and the breaker status input indicates that the
generator is online, a trip will occur once the time delay has expired. The time delay should be used to prevent possible nuisance tripping during shutdown. The field status contact may be chosen as "Auxiliary a", open signifying the field breaker or
contactor is open and shorted signifying the field breaker or contactor is closed. Conversely, the field status contact may be
chosen as "Auxiliary b", shorted signifying the field breaker or contactor is open and open signifying it is closed.
4.4.10 TACHOMETER
PATH: SETPOINTS  S3 DIGITAL INPUTS  TACHOMETER
 TACHOMETER
 [ENTER] for more
ð
4
ð ASSIGN DIGITAL
ESCAPE
ENTER
Range: None, Inputs 4 to 7. Only Digital Inputs 4 to 7
may be assigned to the Tachometer
INPUT: None
ESCAPE
RATED SPEED:
3600 RPM
Range: 100 to 3600 RPM in steps of 1
TACHOMETER
ALARM: Off
Range: Off, Latched, Unlatched
ASSIGN ALARM
RELAYS (2-5): ---5
Range: Any combination of Relays 2 to 5
TACHOMETER ALARM
SPEED: 110% Rated
Range: 101 to 175% in steps of 1
TACHOMETER ALARM
DELAY: 1 s
Range: 1 to 250 s in steps of 1
TACHOMETER ALARM
EVENTS: Off
Range: On, Off
TACHOMETER
TRIP: Off
Range: Off, Latched, Unlatched
ASSIGN TRIP
RELAYS (1-4): 1---
Range: Any combination of Relays 1 to 4
TACHOMETER TRIP
SPEED: 110% Rated
Range: 101 to 175% in steps of 1
TACHOMETER TRIP
DELAY: 1 s
Range: 1 to 250 s in steps of 1
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
4-18
ð ASSIGN DIGITAL
ESCAPE
489 Generator Management Relay
GE Multilin
4 SETPOINTS
4.4 S3 DIGITAL INPUTS
One of assignable digital inputs 4 to 7 may be assigned to the tachometer function to measure mechanical speed. The time
between each input closure is measured and converted to an RPM value based on one closure per revolution. If an overspeed trip or alarm is enabled, and the measured RPM exceeds the threshold setpoint for the time specified by the delay, a
trip or alarm will occur. The RPM value can be viewed with the A2 METERING DATA  SPEED  TACHOMETER actual
value.
For example, an inductive proximity probe or hall effect gear tooth sensor may be used to sense the key on the generator.
The probe could be powered from the +24V from the digital input power supply. The NPN transistor output could be taken
to one of the assignable digital inputs assigned to the tachometer function.
4.4.11 WAVEFORM CAPTURE
PATH: SETPOINTS  S3 DIGITAL INPUTS  WAVEFORM CAPTURE
ð
 WAVEFORM CAPTURE
 [ENTER] for more
ENTER
ESCAPE
ð ASSIGN DIGITAL
INPUT: None
Range: None, Input 1 to Input 7. If an input is assigned to
the Tachometer, it may not be used here.
This feature may be used to trigger the waveform capture from an external contact. When one of the inputs is assigned to
the Waveform Capture function, shorting that input will trigger the waveform.
4.4.12 GROUND SWITCH STATUS
PATH: SETPOINTS  S3 DIGITAL INPUTS  GND SWITCH STATUS
ð
 GND SWITCH STATUS
 [ENTER] for more
ENTER
ESCAPE
ESCAPE
MESSAGE
ð ASSIGN DIGITAL
INPUT: None
GROUND SWITCH
CONTACT: Auxiliary a
Range: None, Input 1 to Input 7. If an input is assigned to
the Tachometer, it may not be used here.
Range: Auxiliary a, Auxiliary b
This function is used to detect the status of a grounding switch for the generator for which the relay is installed. Refer to
Appendix B for Application Notes.
GE Multilin
489 Generator Management Relay
4-19
4
4.5 S4 OUTPUT RELAYS
4 SETPOINTS
4.5S4 OUTPUT RELAYS
4.5.1 DESCRIPTION
Five of the six output relays are always non-failsafe, R6 Service is always failsafe. As failsafe, R6 relay will be energized
normally and de-energize when called upon to operate. It will also de-energize when control power to the 489 is lost and
therefore, be in its operated state. All other relays, being non-failsafe, will be de-energized normally and energize when
called upon to operate. Obviously, when control power is lost to the 489, the output relays must be de-energized and therefore, they will be in their non-operated state. Shorting bars in the drawout case ensure that when the 489 is drawn out, no
trip or alarm occurs. The R6 Service output will however indicate that the 489 has been drawn out.
4.5.2 RELAY RESET MODE
PATH: SETPOINTS  S4 OUTPUT RELAYS  RELAY RESET MODE
ð
 RELAY RESET MODE
 [ENTER] for more
ENTER
ð R1 TRIP:
All Resets
ESCAPE
R2 AUXILIARY:
All Resets
Range: All Resets, Remote Reset Only
R3 AUXILIARY:
All Resets
Range: All Resets, Remote Reset Only
R4 ALARM:
All Resets
Range: All Resets, Remote Reset Only
R5 BLOCK START:
All Resets
Range: All Resets, Remote Reset Only
R6 SERVICE:
All Resets
Range: All Resets, Remote Reset Only
MESSAGE
ESCAPE
4
Range: All Resets, Remote Reset Only
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
Unlatched trips and alarms will reset automatically once the condition is no longer present. Latched trip and alarm features
may be reset at any time, providing that the condition that caused the trip or alarm is no longer present and any lockout time
has expired. If any condition may be reset, the Reset Possible LED will be lit. The relays may be programmed to All Resets
which allows reset from the front keypad or the remote reset digital input or the communications port. Optionally, they may
be programmed to reset by the Remote Reset Only (by the remote reset digital input or the communications port).
For example, selected trips such as Instantaneous Overcurrent and Ground Fault may be assigned to R2 so that they may
only be reset via. the Remote Reset digital input or the Communication Port. The Remote Reset terminals would be connected to a keyswitch so that only authorized personnel could reset such a critical trip.
•
Assign only Short Circuit and Ground Fault to R2
•
Program R2 to Remote Reset Only
4-20
489 Generator Management Relay
GE Multilin
4 SETPOINTS
4.6 S5 CURRENT ELEMENTS
4.6S5 CURRENT ELEMENTS
4.6.1 INVERSE TIME OVERCURRENT CURVE CHARACTERISTICS
a) DESCRIPTION
The 489 inverse time overcurrent curves may be either ANSI, IEC, or GE Type IAC standard curve shapes. This allows for
simplified coordination with downstream devices. If however, none of these curve shapes is adequate, the FlexCurve™
may be used to customize the inverse time curve characteristics. Definite time is also an option that may be appropriate if
only simple protection is required.
Table 4–1: 489 OVERCURRENT CURVE TYPES
ANSI
IEC
GE TYPE IAC
OTHER
ANSI Extremely Inverse
IEC Curve A (BS142)
IAC Extremely Inverse
FlexCurve™
ANSI Very Inverse
IEC Curve B (BS142)
IAC Very Inverse
Definite Time
ANSI Normally Inverse
IEC Curve C (BS142)
IAC Inverse
ANSI Moderately Inverse
IEC Short Inverse
IAC Short Inverse
A multiplier setpoint allows selection of a multiple of the base curve shape that is selected with the curve shape setpoint.
Unlike the electromechanical time dial equivalent, trip times are directly proportional to the time multiplier setting value. For
example, all trip times for a multiplier of 10 are 10 times the multiplier 1 or base curve values. Setting the multiplier to zero
results in an instantaneous response to all current levels above pickup.
Regardless of the trip time that results from the curve multiplier setpoint, the 489 cannot trip any quicker
than one to two cycles plus the operate time of the output relay.
NOTE
Time overcurrent tripping time calculations are made with an internal “energy capacity” memory variable. When this variable indicates that the energy capacity has reached 100%, a time overcurrent trip is generated. If less than 100% is accumulated in this variable and the current falls below the dropout threshold of 97 to 98% of the pickup value, the variable must
be reduced. Two methods of this resetting operation are available, “Instantaneous” and “Linear”. The Instantaneous selection is intended for applications with other relays, such as most static units, which set the energy capacity directly to zero
when the current falls below the reset threshold. The Linear selection can be used where the 489 must coordinate with
electromechanical units. With this setting, the energy capacity variable is decremented according to the following equation.
E × M × CR
T RESET = ----------------------------100
where:
(EQ 4.3)
TRESET = reset time in seconds
E = energy capacity reached (per unit)
M = curve multiplier
CR= characteristic constant (5 for ANSI, IAC, Definite Time and FlexCurves™, 8 for IEC curves)
b) ANSI CURVES
The ANSI time overcurrent curve shapes conform to industry standard curves and fit into the ANSI C37.90 curve classifications for extremely, very, normally, and moderately inverse. The 489 ANSI curves are derived from the formula:


B
E
D
T = M ×  A + ------------------------------------- + --------------------------------------------2- + --------------------------------------------3-
I
I
( ⁄ pickup ) – C ( ( I ⁄ I pickup ) – C )
( ( I ⁄ I pickup ) – C ) 

where:
(EQ 4.4)
T = Trip Time in seconds; M = Multiplier setpoint
I = Input Current; Ipickup = Pickup Current setpoint
A, B, C, D, E = Constants
Table 4–2: ANSI INVERSE TIME CURVE CONSTANTS
ANSI CURVE SHAPE
CONSTANTS
A
B
C
D
E
EXTREMELY INVERSE
0.0399
0.2294
0.5000
3.0094
0.7222
VERY INVERSE
0.0615
0.7989
0.3400
–0.2840
4.0505
NORMALLY INVERSE
0.0274
2.2614
0.3000
–4.1899
9.1272
MODERATELY INVERSE
0.1735
0.6791
0.8000
–0.0800
0.1271
GE Multilin
489 Generator Management Relay
4-21
4
4.6 S5 CURRENT ELEMENTS
4 SETPOINTS
c) IEC CURVES
For European applications, the relay offers the four standard curves defined in IEC 255-4 and British standard BS142.
These are defined as IEC Curve A, IEC Curve B, IEC Curve C, and Short Inverse. The formula for these curves is:


K
-
T = M ×  ------------------------------------- ( I ⁄ I pickup ) E – 1
where:
(EQ 4.5)
T = Trip Time in seconds
M = Multiplier setpoint
I = Input Current
Ipickup = Pickup Current setpoint
K, E = Constants
Table 4–3: IEC (BS) INVERSE TIME CURVE CONSTANTS
IEC (BS) CURVE SHAPE
4
CONSTANTS
K
E
IEC CURVE A (BS142)
0.140
0.020
IEC CURVE B (BS142)
13.500
1.000
IEC CURVE C (BS142)
80.000
2.000
SHORT INVERSE
0.050
0.040
d) IAC CURVES
The curves for the General Electric type IAC relay family are derived from the formula:


B
E
D
T = M ×  A + ------------------------------------- + --------------------------------------------2- + --------------------------------------------3-
I
I
(
⁄
)
–
C
( ( I ⁄ I pickup ) – C )
( ( I ⁄ I pickup ) – C ) 

pickup
where:
(EQ 4.6)
T = Trip Time in seconds
M = Multiplier setpoint
I = Input Current
Ipickup = Pickup Current setpoint
A, B, C, D, E = Constants
Table 4–4: IAC INVERSE TIME CURVE CONSTANTS
IAC CURVE SHAPE
CONSTANTS
A
B
C
D
E
IAC EXTREME INVERSE
0.0040
0.6379
0.6200
1.7872
0.2461
IAC VERY INVERSE
0.0900
0.7955
0.1000
–1.2885
7.9586
IAC INVERSE
0.2078
0.8630
0.8000
–0.4180
0.1947
IAC SHORT INVERSE
0.0428
0.0609
0.6200
–0.0010
0.0221
4-22
489 Generator Management Relay
GE Multilin
4 SETPOINTS
4.6 S5 CURRENT ELEMENTS
e) FLEXCURVE™
The custom FlexCurve™ has setpoints for entering times to trip at the following current levels: 1.03, 1.05, 1.1 to 6.0 in steps
of 0.1 and 6.5 to 20.0 in steps of 0.5. The relay then converts these points to a continuous curve by linear interpolation
between data points. To enter a custom FlexCurve™, read off each individual point from a time overcurrent coordination
drawing and enter it into a table as shown. Then transfer each individual point to the 489 using either the 489PC software
or the front panel keys and display.
Table 4–5: FLEXCURVE™ TRIP TIMES
PICKUP
(I / Ipickup)
TRIP TIME
(MS)
PICKUP
(I / Ipickup)
TRIP TIME
(MS)
PICKUP
(I / Ipickup)
TRIP TIME
(MS)
PICKUP
(I / Ipickup)
1.03
2.9
4.9
10.5
1.05
3.0
5.0
11.0
1.1
3.1
5.1
11.5
1.2
3.2
5.2
12.0
1.3
3.3
5.3
12.5
1.4
3.4
5.4
13.0
1.5
3.5
5.5
13.5
1.6
3.6
5.6
14.0
1.7
3.7
5.7
14.5
1.8
3.8
5.8
15.0
1.9
3.9
5.9
15.5
2.0
4.0
6.0
16.0
2.1
4.1
6.5
16.5
2.2
4.2
7.0
17.0
2.3
4.3
7.5
17.5
2.4
4.4
8.0
18.0
2.5
4.5
8.5
18.5
2.6
4.6
9.0
19.0
2.7
4.7
9.5
19.5
2.8
4.8
10.0
20.0
TRIP TIME
(MS)
4
f) DEFINITE TIME CURVE
The definite time curve shape causes a trip as soon as the pickup level is exceeded for a specified period of time. The base
definite time curve delay is 100 ms. The curve multiplier of 0.00 to 1000.00 makes this delay adjustable from instantaneous
to 100.00 seconds in steps of 1 ms.
T = M × 100 ms, when I > I pickup
where:
(EQ 4.7)
T = Trip Time in seconds
M = Multiplier Setpoint
I = Input Current
Ipickup = Pickup Current Setpoint
GE Multilin
489 Generator Management Relay
4-23
4.6 S5 CURRENT ELEMENTS
4 SETPOINTS
4.6.2 OVERCURRENT ALARM
PATH: SETPOINTS  S5 CURRENT ELEMENTS  OVERCURRENT ALARM
ð
 OVERCURRENT ALARM
 [ENTER] for more
ENTER
Range: Off, Latched, Unlatched
ALARM: Off
ESCAPE
ASSIGN ALARM
RELAYS (2-5): ---5
Range: Any combination of Relays 2 to 5
OVERCURRENT ALARM
LEVEL: 1.01 x FLA
Range: 0.10 to 1.50 × FLA in steps of 0.01
OVERCURRENT ALARM
DELAY: 0.1 s
Range: 0.1 to 250.0 s in steps of 0.1
OVERCURRENT ALARM
EVENTS: Off
Range: On, Off
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
If enabled as Latched or Unlatched, the Overcurrent Alarm will function as follows: If the average generator current (RMS)
measured at the output CTs exceeds the level programmed for the period of time specified, an alarm will occur. If programmed as unlatched, the alarm will reset itself when the overcurrent condition is no longer present. If programmed as
latched, once the overcurrent condition is gone, the reset key must be pressed to reset the alarm. The generator FLA is calculated as:
Generator FLA =
3 × rated generator phase-phase voltage
(EQ 4.8)
4.6.3 OFFLINE OVERCURRENT
PATH: SETPOINTS  S5 CURRENT ELEMENTS  OFFLINE O/C
 OFFLINE O/C
 [ENTER] for more
ð
4
ð OVERCURRENT
ESCAPE
ENTER
ð OFFLINE OVERCURRENT
Range: Off, Latched, Unlatched
ESCAPE
TRIP: Off
ESCAPE
ASSIGN TRIP
RELAYS (1-4): 1---
Range: Any combination of Relays 1 to 4
OFFLINE OVERCURRENT
PICKUP: 0.05 x CT
Range: 0.05 to 1.00 × CT in steps of 0.01
OFFLINE OVERCURRENT
TRIP DELAY: 5 cycles
Range: 3 to 99 cycles in steps of 1
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
When a synchronous generator is offline, there should be no measurable current flow in any of the three phases unless the
unit is supplying its own station load. Also, since the generator is not yet online, differentiation between system faults and
machine faults is easier. The offline overcurrent feature is active only when the generator is offline and uses the neutral end
CT measurements (Ia, Ib, Ic). It may be set much more sensitive than the differential element to detect high impedance
phase faults. Since the breaker auxiliary contacts wired to the 489 Breaker Status input may not operate at exactly the
same time as the main breaker contacts, the time delay should be coordinated with the difference of the operation times. In
the event of a low impedance fault, the differential element will still shutdown the generator quickly.
If the unit auxiliary transformer is on the generator side of the breaker, the pickup level must be set greater
than the unit auxiliary load.
NOTE
4-24
489 Generator Management Relay
GE Multilin
4 SETPOINTS
4.6 S5 CURRENT ELEMENTS
4.6.4 INADVERTENT ENERGIZATION
PATH: SETPOINTS  S5 CURRENT ELEMENTS  INADVERTENT ENERG.
ð
 INADVERTENT ENERG.
 [ENTER] for more
Range: Off, Latched, Unlatched
ð INADVERTENT ENERGIZE
ENTER
ESCAPE
TRIP: Off
ESCAPE
ASSIGN ALARM
RELAYS (1-4): 1---
Range: Any combination of Relays 1 to 4
ARMING SIGNAL:
U/V and Offline
Range: U/V and Offline, U/V or Offline
INADVERTENT ENERGIZE
O/C PICKUP: 0.05 x CT
Range: 0.05 to 3.00 × CT in steps of 0.01
INADVERTENT ENERGIZE
PICKUP: 0.50 x Rated V
Range: 0.50 to 0.99 × Rated Voltage in steps of 0.01
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
The logic diagram for the inadvertent energization protection feature is shown below. The feature may be armed when all of
the phase voltages fall below the undervoltage pickup level and the unit is offline. This would be the case when the VTs are
on the generator side of the disconnect device. If however, the VTs are on the power system side of the disconnect device,
the feature should be armed if all of the phase voltages fall below the undervoltage pickup level or the unit is offline. When
the feature is armed, if any one of the phase currents measured at the output CTs exceeds the overcurrent level programmed, a trip will occur.
5 seconds to arm, 250 ms to disarm.
NOTE
Protection can be provided for poor synchronization by using the "U/V or Offline" arming signal. During normal synchronization, there should be relatively low current measured. If however, synchronization is attempted when conditions are not
appropriate, a large current that is measured within 250 ms after the generator is placed online would result in a trip.
Operate
Iphase > O/C Level
AND
Vphase < U/V Level
Breaker Status = Offline
5s
AND
OR
250 ms
OR
Arming Signal = U/V or Offline
AND
808731A1.CDR
Figure 4–1: INADVERTENT ENERGIZATION
GE Multilin
489 Generator Management Relay
4-25
4
4.6 S5 CURRENT ELEMENTS
4 SETPOINTS
4.6.5 VOLTAGE RESTRAINED PHASE OVERCURRENT
PATH: SETPOINTS  S5 CURRENT ELEMENTS  PHASE OVERCURRENT
ð
 PHASE OVERCURRENT
 [ENTER] for more
ENTER
ð PHASE OVERCURRENT
Range: Off, Latched, Unlatched
ESCAPE
TRIP: Off
ESCAPE
ASSIGN TRIP
RELAYS (1-4): 1---
Range: Any combination of Relays 1 to 4
ENABLE VOLTAGE
RESTRAINT: No
Range: No, Yes
VOLTAGE LOWER
LIMIT: 10%
Range: 10 to 60%. Seen only if ENABLE VOLTAGE
RESTRAINT is "Yes"
PHASE OVERCURRENT
PICKUP: 10.00 x CT
Range: 0.15 to 20.00 × CT in steps of 0.01
CURVE SHAPE:
ANSI Extremely Inv.
Range: See Table 4–1: 489 Overcurrent Curve Types on
page 4–21.
FLEXCURVE TRIP TIME
AT 1.03 x PU: 65535 ms
Range: 0 to 65535 ms
Seen only if CURVE SHAPE is set to "Flexcurve"
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
4
ESCAPE
MESSAGE
↓
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
FLEXCURVE TRIP TIME
AT 20.0 x PU: 65535 ms
Range: 0 to 65535 ms
Seen only if CURVE SHAPE is set to "Flexcurve"
OVERCURRENT CURVE
MULTIPLIER: 1.00
Range: 0.00 to 1000.00 in steps of 0.01
OVERCURRENT CURVE
RESET: Instantaneous
Range: Instantaneous, Linear
If the primary system protection fails to properly isolate phase faults, the voltage restrained overcurrent acts as system
backup protection. The magnitude of each phase current measured at the output CTs is used to time out against an inverse
time curve. The 489 inverse time curve for this element may be either ANSI, IEC, or GE Type IAC standard curve shapes.
This allows for simplified coordination with downstream devices. If these curve shapes are not adequate, FlexCurves™
may be used to customize the inverse time curve characteristics.
The voltage restraint feature lowers the pickup value of each phase time overcurrent element in a fixed relationship (see
figure below) with the corresponding input voltage to a minimum pickup of 0.15 × CT. The VOLTAGE LOWER LIMIT setpoint
prevents very rapid tripping prior to primary protection clearing a fault when voltage restraint is enabled and severe close-in
fault has occurred. If voltage restraint is not required, select "No" for this setpoint. If the VT type is selected as "None" or a
VT fuse loss is detected, the voltage restraint is ignored and the element operates as simple phase overcurrent.
A fuse failure is detected within 99 ms; therefore, any voltage restrained overcurrent trip should have a
time delay of 100 ms or more or nuisance tripping on fuse loss could occur.
NOTE
For example, to determine the voltage restrained phase overcurrent pickup level under the following situation:
"2.00 × CT"
•
PHASE OVERCURRENT PICKUP:
•
ENABLE VOLTAGE RESTRAINT:
•
Phase-Phase Voltage / Rated Phase-Phase Voltage = 0.4 p.u. V
"Yes"
The voltage restrained phase overcurrent pickup level is calculated as follows:
Voltage Restrained Phase OC Pickup = Phase OC Pickup × Voltage Restrained Pickup Curve Multiplier × CT
= ( 2 × 0.4 ) × CT = 0.8 × CT
4-26
489 Generator Management Relay
(EQ 4.9)
GE Multilin
4 SETPOINTS
4.6 S5 CURRENT ELEMENTS
The 489 phase overcurrent restraint voltages and restraint characteristic are shown below:
1
Phase Overcurrent Restraint Voltages:
VOLTAGE
IA
Vab
IB
Vbc
IC
Vca
Curve Pickup Multiplier
CURRENT
0.9
0.8
0.7
0.6
0.5
0.4
0.3
0.2
0.1
808792A4.CDR
0
0
0.1
0.2
0.3
0.4
0.5
0.6
0.7
0.8
0.9
1
Phase-Phase Voltage / Rated Phase-Phase Voltage
Figure 4–2: VOLTAGE RESTRAINT CHARACTERISTIC
4.6.6 NEGATIVE SEQUENCE OVERCURRENT
PATH: SETPOINTS  S5 CURRENT ELEMENTS  NEGATIVE SEQUENCE
ð
 NEGATIVE SEQUENCE
 [ENTER] for more
ENTER
ð NEGATIVE SEQUENCE
Range: Off, Latched, Unlatched
ESCAPE
ALARM: Off
ESCAPE
ASSIGN ALARM
RELAYS (2-5): ---5
Range: Any combination of Relays 2 to 5
NEG. SEQUENCE ALARM
PICKUP: 3% FLA
Range: 3 to 100% FLA in steps of 1
NEGATIVE SEQUENCE
ALARM DELAY: 0.5 s
Range: 0.1 to 100.0 s in steps of 0.1
NEGATIVE SEQUENCE
ALARM EVENTS: Off
Range: On, Off
NEGATIVE SEQUENCE
O/C TRIP: Off
Range: Off, Latched, Unlatched
ASSIGN TRIP
RELAYS (1-4): 1---
Range: Any combination of Relays 1 to 4
NEG. SEQUENCE O/C
TRIP PICKUP: 8% FLA
Range: 3 to 100% FLA in steps of 1
NEG. SEQUENCE O/C
CONSTANT K: 1
Range: 1 to 100 in steps of 1
NEG. SEQUENCE O/C
MAX. TIME: 1000 s
Range: 10 to 1000 s in steps of 1
NEG. SEQUENCE O/C
RESET RATE: 227.0 s
Range: 0.0 to 999.9 s in steps of 0.01
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
Rotor heating in generators due to negative sequence current is a well known phenomenon. Generators have very specific
capability limits where unbalanced current is concerned (see ANSI C50.13). A generator should have a rating for both continuous and also short time operation when negative sequence current components are present.
GE Multilin
489 Generator Management Relay
4-27
4
4.6 S5 CURRENT ELEMENTS
4 SETPOINTS
2
K = I2 T defines the short time negative sequence capability of the generator
where:
(EQ 4.10)
K = constant from generator manufacturer depending on generator size and design
I2 = negative sequence current as a percentage of generator rated FLA as measured at the output CTs
t = time in seconds when I2 > pickup (minimum 250 ms, maximum defined by setpoint)
The 489 has a definite time alarm and inverse time overcurrent curve trip to protect the generator rotor from overheating
due to the presence of negative sequence currents. Pickup values are negative sequence current as a percent of generator
rated full load current. The generator FLA is calculated as:
Generator Rated MVA
Generator FLA = ---------------------------------------------------------------------------------------------------------------------3 × Rated Generator Phase-Phase Voltage
(EQ 4.11)
Negative sequence overcurrent maximum time defines the maximum time that any value of negative sequence current in
excess of the pickup value will be allowed to persist before a trip is issued. The reset rate provides a thermal memory of
previous unbalance conditions. It is the linear reset time from the threshold of trip.
Unusually high negative sequence current levels may be caused by incorrect phase CT wiring.
NOTE
4
808791A2.CDR
Figure 4–3: NEGATIVE SEQUENCE INVERSE TIME CURVES
4-28
489 Generator Management Relay
GE Multilin
4 SETPOINTS
4.6 S5 CURRENT ELEMENTS
4.6.7 GROUND OVERCURRENT
PATH: SETPOINTS  S5 CURRENT ELEMENTS  GROUND O/C
ð
 GROUND O/C
 [ENTER] for more
ENTER
ð GROUND OVERCURRENT
Range: Off, Latched, Unlatched
ESCAPE
ALARM: Off
ESCAPE
ASSIGN ALARM
RELAYS (2-5): ---5
Range: Any combination of Relays 2 to 5
GROUND O/C ALARM
PICKUP: 0.20 x CT
Range: 0.05 to 20.00 × CT in steps of 0.01
GROUND O/C ALARM
DELAY: 0 cycles
Range: 0 to 100 cycles in steps of 1
GROUND OVERCURRENT
ALARM EVENTS: Off
Range: On, Off
GROUND OVERCURRENT
TRIP: Off
Range: Off, Latched, Unlatched
ASSIGN TRIP
RELAYS (1-4): 1---
Range: Any combination of Relays 1 to 4
GROUND O/C TRIP
PICKUP: 0.20 x CT
Range: 0.05 to 20.00 × CT in steps of 0.01
CURVE SHAPE:
ANSI Extremely Inv.
Range: see Table 4–1: 489 Overcurrent Curve Types on
page 4–21.
FLEXCURVE TRIP TIME
AT 1.03 x PU: 65535 ms
Range: 0 to 65535 ms
Seen only if CURVE SHAPE is Flexcurve
FLEXCURVE TRIP TIME
AT 1.05 x PU: 65535 ms
Range: 0 to 65535 ms
Seen only if CURVE SHAPE is Flexcurve
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
4
↓
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
FLEXCURVE TRIP TIME
AT 20.0 x PU: 65535 ms
Range: 0 to 65535 ms
Seen only if CURVE SHAPE is set to Flexcurve
OVERCURRENT CURVE
MULTIPLIER: 1.00
Range: 0.00 to 1000.00 in steps of 0.01
OVERCURRENT CURVE
RESET: Instantaneous
Range: Instantaneous, Linear
The 489 ground overcurrent feature consists of both an alarm and a trip element. The magnitude of measured ground current is used to time out against the definite time alarm or inverse time curve trip. The 489 inverse time curve for this element
may be either ANSI, IEC, or GE Type IAC standard curve shapes. This allows for simplified coordination with downstream
devices. If however, none of these curves shapes is adequate, the FlexCurve™ may be used to customize the inverse time
curve characteristics. If the Ground CT is selected as "None", the ground overcurrent protection is disabled.
The pickup level for the ground current elements is programmable as a multiple of the CT. The 50:0.025 CT
is intended for very sensitive detection of ground faults and its nominal CT rating for the 489 is 50:0.025.
NOTE
For example, if the ground CT is 50:0.025, a pickup of 0.20 would be 0.20 × 5 = 1 A primary. If the ground CT is 50:0.025, a
pickup of 0.05 would be 0.05 × 5 = 0.25 A primary.
GE Multilin
489 Generator Management Relay
4-29
4.6 S5 CURRENT ELEMENTS
4 SETPOINTS
4.6.8 PHASE DIFFERENTIAL
PATH: SETPOINTS  S5 CURRENT ELEMENTS  PHASE DIFFERENTIAL
ð
 PHASE DIFFERENTIAL
 [ENTER] for more
ENTER
Range: Off, Latched, Unlatched
TRIP: Off
ESCAPE
ASSIGN TRIP
RELAYS (1-4): 1---
Range: Any combination of Relays 1 to 4
DIFFERENTIAL TRIP
MIN. PICKUP: 0.10 x CT
Range: 0.05 to 1.00 × CT in steps of 0.01
DIFFERENTIAL TRIP
SLOPE 1: 10%
Range: 1 to 100% in steps of 1
DIFFERENTIAL TRIP
SLOPE 2: 20%
Range: 1 to 100% in steps of 1
DIFFERENTIAL TRIP
DELAY: 0 cycles
Range: 0 to 100 cycles in steps of 10
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
4
ð PHASE DIFFERENTIAL
ESCAPE
The 489 differential element consists of the well known, dual slope, percent restraint characteristic. A differential signal is
derived from the phasor sum of the currents on either side of the machine. A restraint signal is derived from the average of
the magnitudes of these two currents. An internal flag (Diff) is asserted when the differential signal crosses the operating
characteristic as defined by the magnitude of the restraint signal. The Diff flag produces a relay operation.
External faults near generators would typically result in very large time constants of DC components in the fault currents.
Also, when energizing a step-up transformer, the inrush current being limited only by the machine impedance may be significant and may last for a very long time. This creates a real danger of CT saturation. In order to enhance the security of
the relay under these circumstances a directional check is employed.
When the generator is subjected to an external fault the currents will be large but the CTs will initially reproduce the fault
current without distortion. Consequently the relay will see a large restraint signal coupled with a small differential signal.
This condition is used as an indication of the possible onset of CT saturation. An internal flag (SC) will be set at this time.
Once the SC flag has been set, a comparison of the phase angles of the currents on either side of the generator is carried
out. An external fault is inferred if the phase comparison indicates both currents are flowing in the same direction. An internal fault is inferred if the phase comparison indicates that the currents are flowing in opposite directions. In this case an
internal flag (DIR) is set.
If the SC flag is not set, then the relay will operate for a Diff flag alone. If the SC flag is set then the differential flag is supervised by the directional flag. The requirement for both the Diff flag and the Dir flag during the period where CT saturation is
likely therefore enhances the security of the scheme.
The differential element for phase A will operate when:
I operate > k × I restraint
(EQ 4.12)
I operate = I A – I a = operate current
(EQ 4.13)
IA + Ia
- = restraint current
I restraint = -------------------2
(EQ 4.14)
k = characteristic slope of the differential element in percent
k = Slope1 if I R < 2 × CT ; k = Slope2 if I R ≥ 2 × CT
(EQ 4.15)
IA = phase current measured at the output CT
(EQ 4.16)
Ia = phase current measured at the neutral end CT
(EQ 4.17)
where the following hold:
Differential elements for phase B and phase C operate in the same manner.
4-30
489 Generator Management Relay
GE Multilin
4 SETPOINTS
4.6 S5 CURRENT ELEMENTS
1
0.8
0.7
OPERATE
REGION
0.6
Slope 2 = 20%
0.5
0.4
0.3
0.2
Slope 1 = 10%
I
OPERATE
(multiples of CT)
0.9
Minimum Pickup = 0.10 x CT
0.1
0
0
0.5
1
1.5
2
2.5
3
3.5
4
I RESTRAINT (multiples of CT)
4.5
5
808790A2.CDR
4
Figure 4–4: DIFFERENTIAL ELEMENTS
4.6.9 GROUND DIRECTIONAL
PATH: SETPOINTS  S5 CURRENT ELEMENTS  GROUND DIRECTIONAL
ð
 GROUND DIRECTIONAL
 [ENTER] for more
ESCAPE
DIGITAL INPUTS: Yes
Range: Yes, No. Seen only if a digital input is assigned to
Ground Switch Status
ESCAPE
GROUND DIRECTIONAL
MTA: 0°
Range: 0°, 90°, 180°, 270°
Note: MTA = Maximum Torque Angle
GROUND DIRECTIONAL
ALARM: Off
Range: Off, Latched, Unlatched
ASSIGN ALARM
RELAYS (2-5): ---5
Range: Any combination of Relays 2 to 5
GROUND DIR. ALARM
PICKUP: 0.05 x CT
Range: 0.05 to 20.00 × CT in steps of 0.01
GROUND DIR. ALARM
DELAY: 3.0 sec.
Range: 0.1 to 120.0 sec. in steps of 0.1
GROUND DIR. ALARM
EVENTS: Off
Range: On, Off
GROUND DIRECTIONAL
TRIP: Off
Range: Off, Latched, Unlatched
ASSIGN TRIP
RELAYS (1-4): 1---
Range: Any combination of Relays 1 to 4
GROUND DIR. TRIP
PICKUP: 0.05 x CT
Range: 0.05 to 20.00 × CT in steps of 0.01
GROUND DIR. TRIP
DELAY: 3.0 sec.
Range: 0.1 to 120.0 sec. in steps of 0.1
ENTER
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
GE Multilin
ð SUPERVISE WITH
489 Generator Management Relay
4-31
4.6 S5 CURRENT ELEMENTS
4 SETPOINTS
The 489 detects ground directional by using two measurement quantities: V0 and I0. The angle between these quantities
determines if a ground fault is within the generator or not. This function should be coordinated with the 59GN element (95%
stator ground protection) to ensure proper operation of the element. Particularly, this element should be faster. This element must use a core balance CT to derive the I0 signal. Polarity is critical in this element. The protection element is
blocked for neutral voltages, V0, below 2.0 V secondary.
The pickup level for the ground current elements is programmable as a multiple of the CT. The 50:0.025 CT is
intended for very sensitive detection of ground faults and its nominal CT rating for the 489 is 50:0.025.
NOTE
For example, if the ground CT is 50:0.025, a pickup of 0.20 would be 0.20 x 5 = 1 A primary. If the ground CT is 50:0.025, a
pickup of 0.05 would be 0.05 x 5 = 0.25 A primary. Refer to Appendix A.1: Stator Ground Fault on page A–1 for additional
details
AUXILIARY
CONTACT
4
GROUNDING SWITCH
C(B)
C(B)
A
59G
A
B(C)
B(C)
I0
TO Vneutral OF EACH 489
50:0.025
TO 50:0.025
GROUND
INPUTS
808812A3.CDR
Figure 4–5: GROUND DIRECTIONAL DETECTION
4.6.10 HIGH-SET PHASE OVERCURRENT
PATH: SETPOINTS  S5 CURRENT ELEMENTS  HIGH-SET PHASE O/C
ð
 HIGH-SET PHASE O/C
 [ENTER] for more
ENTER
ð HIGH-SET PHASE O/C
Range: Off, Latched, Unlatched
ESCAPE
TRIP: Off
ESCAPE
ASSIGN TRIP
RELAYS (1-4): 1---
Range: Any combination of Relays 1 to 4
HIGH-SET PHASE O/C
PICKUP: 5.00 x CT
Range: 0.15 to 20.00 x CT in steps of 0.01
HIGH-SET PHASE O/C
DELAY: 1.00 s
Range: 0.00 to 100.00 s in steps of 0.01
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
If any individual phase current exceeds the pickup level for the specified trip time a trip will occur if the feature is enabled.
The element operates in both online and offline conditions. This element can be used as a backup feature to other protection elements. In situations where generators are connected in parallel this element would be set above the maximum current contribution from the generator on which the protection is installed. With this setting, the element would provide proper
selective tripping. The basic operating time of the element with no time delay is 50 ms at 50/60 Hz.
4-32
489 Generator Management Relay
GE Multilin
4 SETPOINTS
4.7 S6 VOLTAGE ELEMENTS
4.7S6 VOLTAGE ELEMENTS
4.7.1 UNDERVOLTAGE
PATH: SETPOINTS  S6 VOLTAGE ELEMENTS  UNDERVOLTAGE
ð
 UNDERVOLTAGE
 [ENTER] for more
ENTER
Range: Off, Latched, Unlatched
ð UNDERVOLTAGE
ESCAPE
ALARM: Off
ESCAPE
ASSIGN ALARM
RELAYS (2-5): ---5
Range: Any combination of Relays 2 to 5
UNDERVOLTAGE ALARM
PICKUP: 0.85 x Rated
Range: 0.50 to 0.99 × Rated in steps of 0.01
UNDERVOLTAGE ALARM
DELAY: 3.0 s
Range: 0.2 to 120.0 s in steps of 0.1
UNDERVOLTAGE ALARM
EVENTS: Off
Range: On, Off
UNDERVOLTAGE
TRIP: Off
Range: Off, Latched, Unlatched
ASSIGN TRIP
RELAYS (1-4): 1---
Range: Any combination of Relays 1 to 4
UNDERVOLTAGE TRIP
PICKUP: 0.80 x Rated
Range: 0.50 to 0.99 × Rated in steps of 0.01
UNDERVOLTAGE TRIP
DELAY: 1.0 s
Range: 0.2 to 10.0 s in steps of 0.1
UNDERVOLTAGE CURVE
RESET RATE: 1.4 s
Range: 0.0 to 999.9 s in steps of 0.1
UNDERVOLTAGE CURVE
ELEMENT: Curve
Range: Curve, Definite Time
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
4
The undervoltage elements may be used for protection of the generator and/or its auxiliary equipment during prolonged
undervoltage conditions. They are active only when the generator is online. The alarm element is definite time and the trip
element can be definite time or a curve. When the magnitude of the average phase-phase voltage is less than the pickup ×
the generator rated phase-phase voltage, the element will begin to time out. If the time expires, a trip or alarm will occur.
D
T = ------------------------------------ ,
1 – V ⁄ V pickup
where:
when V < V pickup
(EQ 4.18)
T = trip time in seconds
D = UNDERVOLTAGE TRIP DELAY setpoint
V = actual average phase-phase voltage
Vpickup= UNDERVOLTAGE TRIP PICKUP setpoint
10
3
100
Time to Trip (seconds)
The formula for the undervoltage curve is:
1000
TIME DELAY SETTING
The curve reset rate is a linear reset time from the threshold
of trip. If the VT type is selected as None, VT fuse loss is
detected, or the magnitude of I1< 7.5% CT, the undervoltage
protection is disabled. The pickup levels are insensitive to
frequency over the range of 5 to 90 Hz.
1
0.3
10
1
0.1
0
0.2
0.4
0.6
0.8
1
Multiples of Undervoltage Pickup
808742A1.CDR
GE Multilin
489 Generator Management Relay
4-33
4.7 S6 VOLTAGE ELEMENTS
4 SETPOINTS
4.7.2 OVERVOLTAGE
PATH: SETPOINTS  S6 VOLTAGE ELEMENTS  OVERVOLTAGE
ð
 OVERVOLTAGE
 [ENTER] for more
ENTER
ALARM: Off
ESCAPE
ASSIGN ALARM
RELAYS (2-5): ---5
Range: Any combination of Relays 2 to 5
OVERVOLTAGE ALARM
PICKUP: 1.15 x Rated
Range: 1.01 to 1.50 × Rated in steps of 0.01
OVERVOLTAGE ALARM
DELAY: 3.0 s
Range: 0.2 to 120.0 s in steps of 0.1
OVERVOLTAGE ALARM
EVENTS: Off
Range: On, Off
OVERVOLTAGE
TRIP: Off
Range: Off, Latched, Unlatched
ASSIGN TRIP
RELAYS (1-4): 1---
Range: Any combination of Relays 1 to 4
OVERVOLTAGE TRIP
PICKUP: 1.20 x Rated
Range: 1.01 to 1.50 × Rated in steps of 0.01
OVERVOLTAGE TRIP
DELAY: 1.0 s
Range: 0.1 to 10.0 s in steps of 0.1
OVERVOLTAGE CURVE
RESET RATE: 1.4 s
Range: 0.0 to 999.9 s in steps of 0.1
OVERVOLTAGE CURVE
ELEMENT: Curve
Range: Curve, Definite Time
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
4
Range: Off, Latched, Unlatched
ð OVERVOLTAGE
ESCAPE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
The overvoltage elements may be used for protection of the generator and/or its auxiliary equipment during prolonged overvoltage conditions. They are always active (when the generator is offline or online). The alarm element is definite time and
the trip element can be either definite time or an inverse time curve. When the average of the measured phase-phase voltages rises above the pickup level x the generator rated phase-phase voltage, the element will begin to time out. If the time
expires, a trip or alarm will occur. The reset rate is a linear reset time from the threshold of trip. The pickup levels are insensitive to frequency over the range of 5 to 90 Hz.
The formula for the curve is:
(EQ 4.19)
T = trip time in seconds
D = OVERVOLTAGE TRIP DELAY setpoint
V = actual average phase-phase voltage
Vpickup= OVERVOLTAGE TRIP PICKUP setpoint
100
10
10
3
1
1
0.3
TIME DELAY SETTING
where:
when V > V pickup
Time to Trip (seconds)
D
T = ----------------------------------------- ,
( V ⁄ V pickup ) – 1
1000
0.1
0.1
1
1.1
1.2
1.3
1.4
1.5
1.6
1.7
1.8
1.9
2
Multiples of Overvoltage Pickup
808741A1.CDR
4-34
489 Generator Management Relay
GE Multilin
4 SETPOINTS
4.7 S6 VOLTAGE ELEMENTS
4.7.3 VOLTS/HERTZ
PATH: SETPOINTS  S6 VOLTAGE ELEMENTS  VOLTS/HERTZ
ð
 VOLTS/HERTZ
 [ENTER] for more
ENTER
Range: Off, Latched, Unlatched
ð VOLTS/HERTZ
ESCAPE
ALARM: Off
ESCAPE
ASSIGN ALARM
RELAYS (2-5): ---5
Range: Any combination of Relays 2 to 5
VOLTS/HERTZ ALARM
PICKUP: 1.00 x Nominal
Range: 0.50 to 1.99 × Nominal in steps of 0.01
VOLTS/HERTZ ALARM
DELAY: 3.0 s
Range: 0.1 to 150.0 s in steps of 0.1
VOLTS/HERTZ ALARM
EVENTS: Off
Range: On, Off
VOLTS/HERTZ
TRIP: Off
Range: Off, Latched, Unlatched
ASSIGN TRIP
RELAYS (1-4): 1---
Range: Any combination of Relays 1 to 4
VOLTS/HERTZ TRIP
PICKUP: 1.00 x Nominal
Range: 0.50 to 1.99 × Rated in steps of 0.01
VOLTS/HERTZ TRIP
DELAY: 1.0 s
Range: 0.1 to 150.0 s in steps of 0.1
VOLTS/HERTZ CURVE
RESET RATE: 1.4 s
Range: 0.0 to 999.9 s in steps of 0.1
VOLTS/HERTZ TRIP
ELEMENT: Curve #1
Range: Curve #1, Curve #2, Curve #3, Definite Time
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
4
The Volts/Hertz elements may be used generator and unit transformer protection. They are active as soon as the magnitude and frequency of Vab is measurable. The alarm element is definite time; the trip element can be definite time or a
curve. Once the V/Hz measurement Vab exceeds the pickup level for the specified time, a trip or alarm will occur. The reset
rate is a linear reset time from the threshold of trip and should be set to match cooling characteristics of the protected
equipment. The measurement of V/Hz will be accurate through a frequency range of 5 to 90 Hz. Settings less than 1.00
only apply for special generators such as short circuit testing machines.
1000
The formula for Volts/Hertz Curve 1 is:
V
when ---- > Pickup
F
The V/Hz Curve 1 trip curves are shown on the right
for delay settings of 0.1, 0.3, 1, 3, and 10 seconds.
10
10
1
3
1
0.1
0.3
TIME DELAY SETTING
where: T = trip time in seconds
D = VOLTS/HERTZ TRIP DELAY setpoint
V = RMS measurement of Vab
F = frequency of Vab
VNOM = generator voltage setpoint
FS = generator frequency setpoint
Pickup = VOLTS/HERTZ TRIP PICKUP setpoint
100
Time to Trip (seconds)
D
,
T = ---------------------------------------------------------------------2
V⁄F
 ---------------------------------------------------- – 1
 ( V nom ⁄ F s ) × Pickup
0.1
0.01
1.00
1.20
1.40
1.60
1.80
2.00
Multiples of Volts/Hertz Pickup
808743A1-X1.CDR
GE Multilin
489 Generator Management Relay
4-35
4.7 S6 VOLTAGE ELEMENTS
4 SETPOINTS
1000
The formula for Volts/Hertz Curve 2 is:
V
when ---- > Pickup
F
10
10
3
1
1
0.3
The V/Hz Curve 2 trip curves are shown on the right
for delay settings of 0.1, 0.3, 1, 3, and 10 seconds.
0.1
1.00
TIME DELAY SETTING
where: T = trip time in seconds
D = VOLTS/HERTZ TRIP DELAY setpoint
V = RMS measurement of Vab
F = frequency of Vab
VNOM = generator voltage setpoint
FS = generator frequency setpoint
Pickup = VOLTS/HERTZ TRIP PICKUP setpoint
100
Time to Trip (seconds)
D
T = -------------------------------------------------------------- ,
V
⁄
F
----------------------------------------------------- – 1
( V nom ⁄ F s ) × Pickup
0.1
1.20
1.40
1.60
1.80
2.00
Multiples of Volts/Hertz Pickup
808743A1-X2.CDR
10000
The formula for Volts/Hertz Curve 3 is:
V
when ---- > Pickup
F
The V/Hz Curve 3 trip curves are shown on the right
for delay settings of 0.1, 0.3, 1, 3, and 10 seconds.
100
10
10
3
1
1
0.3
TIME DELAY SETTING
where: T = trip time in seconds
D = VOLTS/HERTZ TRIP DELAY setpoint
V = RMS measurement of Vab
F = frequency of Vab
VNOM = generator voltage setpoint
FS = generator frequency setpoint
Pickup = VOLTS/HERTZ TRIP PICKUP setpoint
1000
Time to Trip (seconds)
D
-,
T = ------------------------------------------------------------------------0.5
V⁄F
 ---------------------------------------------------- – 1
 ( V nom ⁄ F s ) × Pickup
0.1
0.1
1.00
1.20
1.40
1.60
1.80
2.00
Multiples of Voltz/Hertz Pickup
808743A1-X3.CDR
phase-phase voltage ⁄ rated phase-phase voltage
Volts/Hertz is calculated per unit as follows: Volts/Hertz = ---------------------------------------------------------------------------------------------------------------------------------frequency ⁄ rated frequency
NOTE
4.7.4 PHASE REVERSAL
PATH: SETPOINTS  S6 VOLTAGE ELEMENTS  PHASE REVERSAL
 PHASE REVERSAL
 [ENTER] for more
ð
4
ENTER
ESCAPE
ESCAPE
MESSAGE
ð PHASE REVERSAL
Range: Off, Latched, Unlatched
TRIP: Off
ASSIGN TRIP
RELAYS (1-4): 1---
Range: Any combination of Relays 1 to 4
The 489 can detect the phase rotation of the three phase voltages. A trip will occur within 200 ms if the Phase Reversal feature is turned on, the generator is offline, each of the phase-phase voltages is greater than 50% of the generator rated
phase-phase voltage and the phase rotation is not the same as the setpoint. Loss of VT fuses cannot be detected when the
generator is offline and could lead to maloperation of this element. If the VT type is selected as "None", the phase reversal
protection is disabled.
4-36
489 Generator Management Relay
GE Multilin
4 SETPOINTS
4.7 S6 VOLTAGE ELEMENTS
4.7.5 UNDERFREQUENCY
PATH: SETPOINTS  S6 VOLTAGE ELEMENTS  UNDERFREQUENCY
ð
 UNDERFREQUENCY
 [ENTER] for more
ENTER
ð BLOCK UNDERFREQUENCY
Range: 0 to 5 s in steps of 1
ESCAPE
FROM ONLINE: 1 s
ESCAPE
VOLTAGE LEVEL
CUTOFF: 0.50 x Rated
Range: 0.50 to 0.99 × Rated in steps of 0.01
UNDERFREQUENCY
ALARM: Off
Range: Off, Latched, Unlatched
ASSIGN ALARM
RELAYS (2-5): ---5
Range: Any combination of Relays 2 to 5
UNDERFREQUENCY
ALARM LEVEL: 59.50 Hz
Range: 20.00 to 60.00 Hz in steps of 0.01
UNDERFREQUENCY
ALARM DELAY: 5.0 s
Range: 0.1 to 2100.0 s in steps of 0.1
UNDERFREQUENCY
ALARM EVENTS: Off
Range: On, Off
UNDERFREQUENCY
TRIP: Off
Range: Off, Latched, Unlatched
ASSIGN TRIP
RELAYS (1-4): 1---
Range: Any combination of Relays 1 to 4
UNDERFREQUENCY
TRIP LEVEL1: 59.50 Hz
Range: 20.00 to 60.00 Hz in steps of 0.01
UNDERFREQUENCY
TRIP DELAY1: 60.0 s
Range: 0.1 to 2100.0 s in steps of 0.1
UNDERFREQUENCY
TRIP LEVEL2: 58.00 Hz
Range: 20.00 to 60.00 Hz in steps of 0.01
UNDERFREQUENCY
TRIP DELAY2: 30.0 s
Range: 0.1 to 2100.0 s in steps of 0.1
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
4
The SR489 relay can be programmed to delay beyond 2100.0 seconds but the response time is not guaranteed.
NOTE
It may be undesirable to enable the underfrequency elements until the generator is online. This feature can be blocked until
the generator is online and the block time expires. From that point forward, the underfrequency trip and alarm elements will
be active. A value of zero for the block time indicates that the underfrequency protection is active as soon as voltage
exceeds the cutoff level (programmed as a multiple of the generator rated phase-phase voltage). Frequency is then measured. Once the frequency of Vab is less than the underfrequency setpoints, for the period of time specified, a trip or alarm
will occur. There are dual level and time setpoints for the trip element.
GE Multilin
489 Generator Management Relay
4-37
4.7 S6 VOLTAGE ELEMENTS
4 SETPOINTS
4.7.6 OVERFREQUENCY
PATH: SETPOINTS  S6 VOLTAGE ELEMENTS  OVERFREQUENCY
ð
 OVERFREQUENCY
 [ENTER] for more
ENTER
Range: 0 to 5 s in steps of 1
FROM ONLINE: 1 s
ESCAPE
VOLTAGE LEVEL
CUTOFF: 0.50 x Rated
Range: 0.50 to 0.99 × Rated in steps of 0.01
OVERFREQUENCY
ALARM: Off
Range: Off, Latched, Unlatched
ASSIGN ALARM
RELAYS (2-5): ---5
Range: Any combination of Relays 2 to 5
OVERFREQUENCY
ALARM LEVEL: 60.50 Hz
Range: 25.01 to 70.00 Hz in steps of 0.01
OVERFREQUENCY
ALARM DELAY: 5.0 s
Range: 0.1 to 2100.0 s in steps of 0.1
OVERFREQUENCY
ALARM EVENTS: Off
Range: On, Off
OVERFREQUENCY
TRIP: Off
Range: Off, Latched, Unlatched
ASSIGN TRIP
RELAYS (1-4): 1---
Range: Any combination of Relays 1 to 4
OVERFREQUENCY
TRIP LEVEL1: 60.50 Hz
Range: 25.01 to 70.00 Hz in steps of 0.01
OVERFREQUENCY
TRIP DELAY1: 60.0 s
Range: 0.1 to 2100.0 s in steps of 0.1
OVERFREQUENCY
TRIP LEVEL2: 62.00 Hz
Range: 25.01 to 70.00 Hz in steps of 0.01
OVERFREQUENCY
TRIP DELAY2: 30.0 s
Range: 0.1 to 2100.0 s in steps of 0.1
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
4
ð BLOCK OVERFREQUENCY
ESCAPE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
The SR489 relay can be programmed to delay beyond 2100.0 seconds but the response time is not guaranteed.
NOTE
It may be undesirable to enable the overfrequency elements until the generator is online. This feature can be blocked until
the generator is online and the block time expires. From that point forward, the overfrequency trip and alarm elements will
be active. A value of zero for the block time indicates that the overfrequency protection is active as soon as voltage
exceeds the cutoff level (programmed as a multiple of the generator rated phase-phase voltage). Frequency is then measured. Once the frequency of Vab exceeds the overfrequency setpoints, for the period of time specified, a trip or alarm will
occur. There are dual level and time setpoints for the trip element.
4-38
489 Generator Management Relay
GE Multilin
4 SETPOINTS
4.7 S6 VOLTAGE ELEMENTS
4.7.7 NEUTRAL OVERVOLTAGE (FUNDAMENTAL)
PATH: SETPOINTS  S6 VOLTAGE ELEMENTS  O/V (FUND)
ð
 NEUTRAL O/V (FUND)
 [ENTER] for more
ENTER
Range: Yes, No. Seen only if a digital input assigned to
GROUND SWITCH STATUS
ð SUPERVISE WITH
ESCAPE
DIGITAL INPUT: No
ESCAPE
NEUTRAL OVERVOLTAGE
ALARM: Off
Range: Off, Latched, Unlatched
ASSIGN ALARM
RELAYS (2-5): ---5
Range: Any combination of Relays 2 to 5
NEUTRAL O/V ALARM
LEVEL: 3.0 Vsec
Range: 2.0 to 100.0 Vsec in steps of 0.1
NEUTRAL OVERVOLTAGE
ALARM DELAY: 1.0 s
Range: 0.1 to 120.0 s in steps of 0.1
NEUTRAL OVERVOLTAGE
ALARM EVENTS: Off
Range: On, Off
NEUTRAL OVERVOLTAGE
TRIP: Off
Range: Off, Latched, Unlatched
ASSIGN TRIP
RELAYS (1-4): 1---
Range: Any combination of Relays 1 to 4
NEUTRAL O/V TRIP
LEVEL: 5.0 Vsec
Range: 2.0 to 100.0 Vsec in steps of 0.1
NEUTRAL OVERVOLTAGE
TRIP DELAY: 1.0 s
Range:
NEUTRAL O/V CURVE
RESET RATE: 0.0
Range: 0.0 to 999.9 in steps of 0.1
NEUTRAL O/V TRIP
ELEMENT: Definite Time
Range: Curve, Definite Time
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
4
0.1 to 120.0 s in steps of 0.1
The neutral overvoltage function responds to fundamental frequency voltage at the generator neutral. It provides ground
fault protection for approximately 95% of the stator windings. 100% protection is provided when this element is used in conjunction with the Neutral Undervoltage (3rd harmonic) function. The alarm element is definite time and the trip element can
be either definite time or an inverse time curve. When the neutral voltage rises above the pickup level the element will begin
to time out. If the time expires an alarm or trip will occur. The reset rate is a linear reset time from the threshold of trip. The
alarm and trip levels are programmable in terms of Neutral VT secondary voltage.
1000
The formula for the curve is:
(EQ 4.20)
T = trip time in seconds
D = NEUTRAL OVERVOLTAGE TRIP DELAY setpoint
V = neutral voltage
Vpickup = NEUTRAL O/V TRIP LEVEL setpoint
The neutral overvoltage curves are shown on the right.
Refer to Appendix B for Application Notes.
100
10
10
3
1
1
0.3
TIME DELAY SETTING
where
when V > V pickup
Time to Trip (seconds)
D
T = ----------------------------------------( V ⁄ V pickup ) – 1
0.1
0.1
1
1.1
1.2
1.3
1.4
1.5
1.6
1.7
1.8
1.9
2
Multiples of Overvoltage Pickup
808741A1.CDR
GE Multilin
489 Generator Management Relay
4-39
4.7 S6 VOLTAGE ELEMENTS
4 SETPOINTS
AUXILIARY CONTACT
TO DIGITAL INPUT FOR
NEUTRAL O/V SUPERVISION
GROUNDING SWITCH
C(B)
C(B)
A
59G
A
B(C)
GENERATOR 1
B(C)
GENERATOR 2
808816A3.CDR
TO Vneutral OF EACH 489
4
Figure 4–6: NEUTRAL OVERVOLTAGE DETECTION
NOTE
If the ground directional element is enabled, the Neutral Overvoltage element should be coordinated with it. In
cases of paralleled generator grounds through the same point, with individual ground switches, per sketch below, it
is recommended to use a ground switch status function to prevent maloperation of the element.
4.7.8 NEUTRAL OVERVOLTAGE (3RD HARMONIC)
PATH: SETPOINTS  S6 VOLTAGE ELEMENTS  NEUTRAL U/V (3RD)
ð
 NEUTRAL U/V (3rd)
 [ENTER] for more
ESCAPE
LEVEL: 0.05 x Rated MW
Range: 0.02 to 0.99 × Rated MW in steps of 0.01
Seen only if VT CONNECTION is "Delta"
ESCAPE
LOW VOLTAGE BLOCKING
LEVEL: 0.75 x Rated
Range: 0.50 to 1.00 × Rated in steps of 0.01
Seen only if VT CONNECTION is "Delta"
NEUTRAL UNDERVOLTAGE
ALARM: Off
Range: Off, Latched, Unlatched
ASSIGN ALARM
RELAYS (2-5): ---5
Range: Any combination of Relays 2 to 5
NEUTRAL U/V ALARM
LEVEL: 0.5 Vsec
Range: 0.5 to 20.0 Vsec in steps of 0.1
Seen only if VT CONNECTION is "Delta"
NEUTRAL UNDERVOLTAGE
ALARM DELAY: 30 s
Range: 5 to 120 s in steps of 1
NEUTRAL UNDERVOLTAGE
ALARM EVENTS: Off
Range: On, Off
NEUTRAL UNDERVOLTAGE
TRIP: Off
Range: Off, Latched, Unlatched
ASSIGN TRIP
RELAYS (1-4): 1---
Range: Any combination of Relays 1 to 4
NEUTRAL U/V TRIP
LEVEL: 1.0 Vsec
Range: 0.5 to 20.0 Vsec in steps of 0.1
Seen only if VT CONNECTION is "Delta"
NEUTRAL UNDERVOLTAGE
TRIP DELAY: 30 s
Range: 5 to 120 s in steps of 1
ENTER
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
4-40
ð LOW POWER BLOCKING
489 Generator Management Relay
GE Multilin
4 SETPOINTS
4.7 S6 VOLTAGE ELEMENTS
The neutral undervoltage function responds to 3rd harmonic voltage measured at the generator neutral and output terminals. When used in conjunction with the Neutral Overvoltage (fundamental frequency) function, it provides 100% ground
fault protection of the stator windings.
WYE CONNECTED VTS:
Since the amount of third harmonic voltage that appears in the neutral is both load and machine dependent, the protection
method of choice is an adaptive method. If the phase VT connection is wye, the following formula is used to create an
adaptive neutral undervoltage pickup level based on the amount of third harmonic that appears at the generator terminals.
V N3
-------------------------------------- ≤ 0.15 which simplifies to V P3 ≥ 17V N3
( V P3 ⁄ 3 ) + V N3
(EQ 4.21)
The 489 tests the following permissives prior to testing the basic operating equation to ensure that VN3’ should be of a measurable magnitude for an unfaulted generator:
V P3 ′ > 0.25 volts
where:
and
Neutral VT Ratio
V P3 ′ ≥ Permissive Threshold × 17 × -------------------------------------------Phase VT Ratio
(EQ 4.22)
VN3 = the magnitude of the third harmonic voltage at generator neutral
VP3 = the magnitude of the third harmonic voltage at the generator terminals
VP3´ = the VT secondary magnitude of the third harmonic voltage measured at the generator terminals
VN3´ = the VT secondary magnitude of the third harmonic voltage at generator neutral
Permissive Threshold = 0.15 volts for the alarm element and 0.1875 volts for the trip element
4
Refer to Appendix B for Application Notes.
OPEN DELTA CONNECTED VTS:
If the phase VT connection is open delta, it is not possible to measure the third harmonic voltages at the generator terminals and a simple third harmonic neutral undervoltage element is used. The level is programmable in terms of Neutral VT
secondary voltage. In order to prevent nuisance tripping at low load or low generator voltages, two blocking functions are
provided. They apply to both the alarm and trip functions. When used as a simple undervoltage element, settings should be
based on measured 3rd harmonic neutral voltage of the healthy machine.
This method of using 3rd harmonic voltages to detect stator ground faults near the generator neutral has proved
feasible on generators with unit transformers. Its usefulness in other generator applications is unknown.
NOTE
GE Multilin
489 Generator Management Relay
4-41
4.7 S6 VOLTAGE ELEMENTS
4 SETPOINTS
4.7.9 LOSS OF EXCITATION
PATH: SETPOINTS  S6 VOLTAGE ELEMENTS  LOSS OF EXCITATION
ð
 LOSS OF EXCITATION
 [ENTER] for more
ENTER
Range: Yes, No
SUPERVISION: Yes
ESCAPE
VOLTAGE
LEVEL: 0.70 x Rated
Range: 0.70 to 1.00 × Rated in steps of 0.01. Seen only if
ENABLE VOLTAGE SUPERVISION is "Yes"
CIRCLE 1
TRIP: Off
Range: Off, Latched, Unlatched
ASSIGN CIRCLE 1 TRIP
RELAYS (1-4): 1---
Range: Any combination of Relays 1 to 4
CIRCLE 1
DIAMETER: 25.0 Ωsec
Range: 2.5 to 300.0 Ωsec in steps of 0.1
CIRCLE 1
OFFSET: 2.5 Ωsec
Range: 1.0 to 300.0 Ωsec in steps of 0.1
CIRCLE 1 TRIP
DELAY: 5.0 s
Range: 0.1 to 10.0 s in steps of 0.1
CIRCLE 2
TRIP: Off
Range: Off, Latched, Unlatched
ASSIGN CIRCLE 2 TRIP
RELAYS (1-4): 1---
Range: Any combination of Relays 1 to 4
CIRCLE 2
DIAMETER: 35.0 Ωsec
Range: 2.5 to 300.0 Ωsec in steps of 0.1
CIRCLE 2
OFFSET: 2.5 Ωsec
Range: 1.0 to 300.0 Ωsec in steps of 0.1
CIRCLE 2 TRIP
DELAY: 5.0 s
Range: 0.1 to 10.0 s in steps of 0.1
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
4
ð ENABLE VOLTAGE
ESCAPE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
Loss of excitation is detected with an impedance element. When the impedance falls within the impedance circle for the
specified delay time, a trip will occur if it is enabled. Circles 1 and/or 2 can be tuned to a particular system. The larger circle
diameter should be set to the synchronous reactance of the generator, xd, and the circle offset to the generator transient
reactance x’d / 2. Typically the smaller circle (if used) is set to minimum time with a diameter set to 0.7xd and an offset of
x’d / 2. This feature is blocked if voltage supervision is enabled and the generator voltage is above the VOLTAGE LEVEL setpoint. The trip feature is supervised by minimum current of 0.05 × CT. Note that the Loss of Excitation element will be
blocked if there is a VT fuse failure or if the generator is offline. Also, it uses output CT inputs.
The secondary phase-phase loss of excitation impedance is defined as:
V AB
Z loe = --------------= M loe ∠θ loe
IA – IB
where:
(EQ 4.23)
Zloe = secondary phase-to-phase loss of excitation impedance
Mloe∠θloe= Secondary impedance phasor (magnitude and angle)
All relay quantities are in terms of secondary impedances. The formula to convert primary impedance quantities to secondary impedance quantities is provided below.
Z primary × CT Ratio
Z sec ondary = -------------------------------------------------VT Ratio
4-42
489 Generator Management Relay
(EQ 4.24)
GE Multilin
4 SETPOINTS
where:
4.7 S6 VOLTAGE ELEMENTS
Zprimary= primary ohms impedance
CT Ratio = programmed CT ratio, if CT ratio is 1200:5 use a value of 1200 / 5 = 240
VT Ratio = programmed VT ratio, if VT ratio is 100:1 use a value of 100
4
Figure 4–7: LOSS OF EXCITATION R-X DIAGRAM
4.7.10 DISTANCE ELEMENT
PATH: SETPOINTS  S6 VOLTAGE ELEMENTS  DISTANCE ELEMENT
ð
 DISTANCE ELEMENT
 [ENTER] for more
ENTER
Range: None, Delta/Wye
SETUP: None
ESCAPE
FUSE FAILURE
SUPERVISION: On
Range: On, Off
ZONE #1
TRIP: Off
Range: Off, Latched, Unlatched
ASSIGN ZONE #1 TRIP
RELAYS (1-4): 1---
Range: Any combination of Relays 1 to 4
ZONE #1
REACH: 10.0 Ωsec
Range: 0.1 to 500.0 Ωsec in steps of 0.1
ZONE #1
ANGLE: 75°
Range: 50 to 85° in steps of 1
ZONE #1 TRIP
DELAY: 0.4 s
Range: 0.0 to 150.0 s in steps of 0.1
ZONE #2
TRIP: Off
Range: Off, Latched, Unlatched
ASSIGN ZONE #2 TRIP
RELAYS (1-4): 1---
Range: Any combination of Relays 1 to 4
ZONE #2
REACH: 15.0 Ωsec
Range: 0.1 to 500.0 Ωsec in steps of 0.1
ZONE #2
ANGLE: 75°
Range: 50 to 85° in steps of 1
ZONE #2 TRIP
DELAY: 2.0 s
Range: 0.0 to 150.0 s in steps of 0.1
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
GE Multilin
ð STEP UP TRANSFORMER
ESCAPE
489 Generator Management Relay
4-43
4.7 S6 VOLTAGE ELEMENTS
4 SETPOINTS
The distance protection function (ANSI device 21) implements two zones of mho phase-to-phase distance protection (six
elements total) using the conventional phase comparator approach, with the polarizing voltage derived from the pre-fault
positive sequence voltage of the protected loop. This protection is intended as backup for the primary line protection. The
elements make use of the neutral-end current signals and the generator terminal voltage signals (see figure below), thus
providing some protection for internal and unit transformer faults. In systems with a delta-wye transformer (DY330°), the
appropriate transformations of voltage and current signals are implemented internally to allow proper detection of transformer high-side phase-to-phase faults. The reach setting is the positive sequence impedance to be covered, per phase,
expressed in secondary ohms. The same transformation shown for the Loss of Excitation element can be used to calculate
the desired settings as functions of the primary-side impedances.
The elements have a basic operating time of 150 ms. A VT fuse failure could cause a maloperation of a distance element
unless the element is supervised by the VTFF element. In order to prevent nuisance tripping the elements require a minimum phase current of 0.05 x CT.
Protection Zone 1
Protection Zone 2
Neutral End CT
52
4
Terminal VT
489
Relay
808740A1.CDR
Figure 4–8: DISTANCE ELEMENT SETUP
4-44
489 Generator Management Relay
GE Multilin
4 SETPOINTS
4.8S7 POWER ELEMENTS
4.8 S7 POWER ELEMENTS
4.8.1 POWER MEASUREMENT CONVENTIONS
Generation of power will be displayed on the 489 as positive watts. By convention, an induction generator normally requires
reactive power from the system for excitation. This is displayed on the 489 as negative vars. A synchronous generator on
the other hand has its own source of excitation and can be operated with either lagging or leading power factor. This is displayed on the 489 as positive vars and negative vars, respectively. All power quantities are measured from the phasephase voltage and the currents measured at the output CTs.
^
I
1
4
^
I
2
^
I
3
^
I
4
Figure 4–9: POWER MEASUREMENT CONVENTIONS
GE Multilin
489 Generator Management Relay
4-45
4.8 S7 POWER ELEMENTS
4 SETPOINTS
4.8.2 REACTIVE POWER
PATH: SETPOINTS  S7 POWER ELEMENTS  REACTIVE POWER
ð
 REACTIVE POWER
 [ENTER] for more
ENTER
Range: 0 to 5000 s in steps of 1
FROM START: 1 s
ESCAPE
REACTIVE POWER
ALARM: Off
Range: Off, Latched, Unlatched
ASSIGN ALARM
RELAYS (2-5): ---5
Range: Any combination of Relays 2 to 5
POSITIVE Mvar ALARM
LEVEL: 0.85 x Rated
Range: 0.02 to 2.01 × Rated in steps of 0.01
NEGATIVE Mvar ALARM
LEVEL: 0.85 x Rated
Range: 0.02 to 2.01 × Rated in steps of 0.01
POSITIVE Mvar ALARM
DELAY: 10.0 s
Range: 0.2 to 120.0 s in steps of 0.1
Note: Lagging vars, overexcited
NEGATIVE Mvar ALARM
DELAY: 1.0 s
Range: 0.2 to 120.0 s in steps of 0.1
Note: Leading vars, underexcited
REACTIVE POWER ALARM
EVENTS: Off
Range: On, Off
REACTIVE POWER
TRIP: Off
Range: Off, Latched, Unlatched
ASSIGN TRIP
RELAYS (1-4): 1---
Range: Any combination of Relays 1 to 4
POSITIVE Mvar TRIP
LEVEL: 0.80 x Rated
Range: 0.02 to 2.01 × Rated in steps of 0.01
NEGATIVE Mvar TRIP
LEVEL: 0.80 x Rated
Range: 0.02 to 2.01 × Rated in steps of 0.01
POSITIVE Mvar TRIP
DELAY: 20.0 s
Range: 0.2 to 120.0 s in steps of 0.1
Note: Lagging vars, overexcited
NEGATIVE Mvar TRIP
DELAY: 20.0 s
Range: 0.2 to 120.0 s in steps of 0.1
Note: Leading vars, underexcited
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
4
ð BLOCK Mvar ELEMENT
ESCAPE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
In a motor/generator application, it may be desirable not to trip or alarm on reactive power until the machine is online and
the field has been applied. Therefore, this feature can be blocked until the machine is online and adequate time has expired
during which the field had been applied. From that point forward, the reactive power trip and alarm elements will be active.
A value of zero for the block time indicates that the reactive power protection is active as soon as both current and voltage
are measured regardless of whether the generator is online or offline. Once the 3-phase total reactive power exceeds the
positive or negative level, for the specified delay, a trip or alarm will occur indicating a positive or negative Mvar condition.
The level is programmed in per unit of generator rated Mvar calculated from the rated MVA and rated power factor. The
reactive power elements can be used to detect loss of excitation. If the VT type is selected as "None" or VT fuse loss is
detected, the reactive power protection is disabled. Rated Mvars for the system can be calculated as follows:
For example, given Rated MVA = 100 MVA and Rated Power Factor = 0.85, we have
–1
–1
Rated Mvars = Rated MVA × sin ( cos ( Rated PF ) ) = 100 × sin ( cos ( 0.85 ) ) = 52.67 Mvars
4-46
489 Generator Management Relay
(EQ 4.25)
GE Multilin
4 SETPOINTS
4.8 S7 POWER ELEMENTS
4.8.3 REVERSE POWER
PATH: SETPOINTS  S7 POWER ELEMENTS  REVERSE POWER
ð
 REVERSE POWER
 [ENTER] for more
ENTER
ð BLOCK REVERSE POWER
Range: 0 to 5000 s in steps of 1
ESCAPE
FROM ONLINE: 1 s
ESCAPE
REVERSE POWER
ALARM: Off
Range: Off, Latched, Unlatched
ASSIGN ALARM
RELAYS (2-5): ---5
Range: Any combination of Relays 2 to 5
REVERSE POWER ALARM
LEVEL: 0.05 x Rated MW
Range: 0.02 to 0.99 × Rated MW in steps of 0.01
REVERSE POWER ALARM
DELAY: 10.0 s
Range: 0.2 to 120.0 s in steps of 0.1
REVERSE POWER ALARM
EVENTS: Off
Range: On, Off
REVERSE POWER
TRIP: Off
Range: Off, Latched, Unlatched
ASSIGN TRIP
RELAYS (1-4): 1---
Range: Any combination of Relays 1 to 4
REVERSE POWER TRIP
LEVEL: 0.05 x Rated MW
Range: 0.02 to 0.99 × Rated MW in steps of 0.01
REVERSE POWER TRIP
DELAY: 20.0 s
Range: 0.2 to 120.0 s in steps of 0.1
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
4
If enabled, once the magnitude of 3-phase total power exceeds the Pickup Level in the reverse direction (negative MW) for
a period of time specified by the Delay, a trip or alarm will occur. The level is programmed in per unit of generator rated MW
calculated from the rated MVA and rated power factor. If the generator is accelerated from the power system rather than the
prime mover, the reverse power element may be blocked from start for a specified period of time. A value of zero for the
block time indicates that the reverse power protection is active as soon as both current and voltage are measured regardless of whether the generator is online or offline. If the VT type is selected as "None" or VT fuse loss is detected, the
reverse power protection is disabled.
NOTE
The minimum magnitude of power measurement is determined by the phase CT minimum of 2% rated CT primary.
If the level for reverse power is set below that level, a trip or alarm will only occur once the phase current exceeds
the 2% cutoff.
Users are cautioned that a reverse power element may not provide reliable indication when set to a very low setting, particularly under conditions of large reactive loading on the generator. Under such conditions, low forward power is a more reliable element.
GE Multilin
489 Generator Management Relay
4-47
4.8 S7 POWER ELEMENTS
4 SETPOINTS
4.8.4 LOW FORWARD POWER
PATH: SETPOINTS  S7 POWER ELEMENTS  LOW FORWARD POWER
ð
 LOW FORWARD POWER
 [ENTER] for more
ENTER
Range: 0 to 15000 s in steps of 1
FROM ONLINE: 0 s
ESCAPE
LOW FORWARD POWER
ALARM: Off
Range: Off, Latched, Unlatched
ASSIGN ALARM
RELAYS (2-5): ---5
Range: Any combination of Relays 2 to 5
LOW FWD POWER ALARM
LEVEL: 0.05 x Rated MW
Range: 0.02 to 0.99 × Rated MW in steps of 0.01
LOW FWD POWER ALARM
DELAY: 10.0 s
Range: 0.2 to 120.0 s in steps of 0.1
LOW FWD POWER ALARM
EVENTS: Off
Range: On, Off
LOW FORWARD POWER
TRIP: Off
Range: Off, Latched, Unlatched
ASSIGN TRIP
RELAYS (1-4): 1---
Range: Any combination of Relays 1 to 4
LOW FWD POWER TRIP
LEVEL: 0.05 x Rated MW
Range: 0.02 to 0.99 × Rated MW in steps of 0.01
LOW FWD POWER TRIP
DELAY: 20.0 s
Range: 0.2 to 120.0 s in steps of 0.1
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
4
ð BLOCK LOW FWD POWER
ESCAPE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
If enabled, once the magnitude of 3-phase total power in the forward direction (+MW) falls below the Pickup Level for a
period of time specified by the Delay, an alarm will occur. The level is programmed in per unit of generator rated MW calculated from the rated MVA and rated power factor. The low forward power element is active only when the generator is online
and will be blocked until the generator is brought online, for a period of time defined by the setpoint Block Low Fwd Power
From Online. The pickup level should be set lower than expected generator loading during normal operations. If the VT
type is selected as "None" or VT fuse loss is detected, the low forward power protection is disabled.
4-48
489 Generator Management Relay
GE Multilin
4 SETPOINTS
4.9 S8 RTD TEMPERATURE
4.9S8 RTD TEMPERATURE
4.9.1 RTD TYPES
PATH: SETPOINTS  S8 RTD TEMPERATURE  RTD TYPES
ð
 RTD TYPES
 [ENTER] for more
ESCAPE
100 Ohm Platinum
Range: 100 Ohm Platinum, 120 Ohm Nickel
100 Ohm Nickel, 10 Ohm Copper
ESCAPE
BEARING RTD TYPE:
100 Ohm Platinum
Range: 100 Ohm Platinum, 120 Ohm Nickel
100 Ohm Nickel, 10 Ohm Copper
AMBIENT RTD TYPE:
100 Ohm Platinum
Range: 100 Ohm Platinum, 120 Ohm Nickel
100 Ohm Nickel, 10 Ohm Copper
OTHER RTD TYPE:
100 Ohm Platinum
Range: 100 Ohm Platinum, 120 Ohm Nickel
100 Ohm Nickel, 10 Ohm Copper
ð STATOR RTD TYPE:
ENTER
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
Each of the twelve RTDs may be configured as None or any one of four application types, Stator, Bearing, Ambient, or
Other. Each of those types may in turn be any one of four different RTD types: 100 ohm Platinum, 120 ohm Nickel, 100 ohm
Nickel, 10 ohm Copper. The table below lists RTD resistance vs. temperature.
4
Table 4–6: RTD TEMPERATURE VS. RESISTANCE
TEMP
°CELSIUS
TEMP
°FAHRENHEIT
100 Ω PT
(DIN 43760)
120 Ω NI
100 Ω NI
10 Ω CU
–50
–58
80.31
86.17
71.81
7.10
–40
–40
84.27
92.76
77.30
7.49
–30
–22
88.22
99.41
82.84
7.88
–20
–4
92.16
106.15
88.45
8.26
–10
14
96.09
113.00
94.17
8.65
0
32
100.00
120.00
100.00
9.04
10
50
103.90
127.17
105.97
9.42
20
68
107.79
134.52
112.10
9.81
30
86
111.67
142.06
118.38
10.19
40
104
115.54
149.79
124.82
10.58
50
122
119.39
157.74
131.45
10.97
60
140
123.24
165.90
138.25
11.35
70
158
127.07
174.25
145.20
11.74
80
176
130.89
182.84
152.37
12.12
90
194
134.70
191.64
159.70
12.51
100
212
138.50
200.64
167.20
12.90
110
230
142.29
209.85
174.87
13.28
120
248
146.06
219.29
182.75
13.67
130
266
149.82
228.96
190.80
14.06
140
284
153.58
238.85
199.04
14.44
150
302
157.32
248.95
207.45
14.83
160
320
161.04
259.30
216.08
15.22
170
338
164.76
269.91
224.92
15.61
180
356
168.47
280.77
233.97
16.00
190
374
172.46
291.96
243.30
16.39
200
392
175.84
303.46
252.88
16.78
210
410
179.51
315.31
262.76
17.17
220
428
183.17
327.54
272.94
17.56
230
446
186.82
340.14
283.45
17.95
240
464
190.45
353.14
294.28
18.34
250
482
194.08
366.53
305.44
18.73
GE Multilin
489 Generator Management Relay
4-49
4.9 S8 RTD TEMPERATURE
4 SETPOINTS
4.9.2 RTDS 1 TO 6
PATH: SETPOINTS  S8 RTD TEMPERATURE  RTD #1(6)
ð
 RTD #1
 [ENTER] for more
ENTER
ð RTD #1 APPLICATION:
Range: Stator, Bearing, Ambient, Other, None
ESCAPE
Stator
ESCAPE
RTD #1 NAME:
Range: 8 alphanumeric characters
RTD #1 ALARM:
Off
Range: Off, Latched, Unlatched
ASSIGN ALARM
RELAYS (2-5): ---5
Range: Any combination of Relays 2 to 5.
RTD #1 ALARM
TEMPERATURE: 130°C
Range: 1 to 250°C in steps of 1
RTD #1 ALARM
EVENTS: Off
Range: On, Off
RTD #1 TRIP:
Off
Range: Off, Latched, Unlatched
RTD #1 TRIP VOTING:
RTD #1
Range: RTD #1 to RTD #12
ASSIGN TRIP
RELAYS (1-4): 1---
Range: Any combination of Relays 1 to 4
RTD #1 TRIP
TEMPERATURE: 155°C
Range: 1 to 250°C in steps of 1
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
4
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
RTDs 1 through 6 default to Stator RTD type. There are individual alarm and trip configurations for each RTD. This allows
one of the RTDs to be turned off if it malfunctions. The alarm level is normally set slightly above the normal running temperature. The trip level is normally set at the insulation rating. Trip voting has been added for extra reliability in the event of
RTD malfunction. If enabled, a second RTD must also exceed the trip temperature of the RTD being checked before a trip
will be issued. If the RTD is chosen to vote with itself, the voting feature is disabled. Each RTD name may be changed if
desired.
4-50
489 Generator Management Relay
GE Multilin
4 SETPOINTS
4.9 S8 RTD TEMPERATURE
4.9.3 RTDS 7 TO 10
PATH: SETPOINTS  S8 RTD TEMPERATURE  RTD #7(10)
ð
 RTD #7
 [ENTER] for more
ENTER
ð RTD #7 APPLICATION:
Range: Stator, Bearing, Ambient, Other, None
ESCAPE
Bearing
ESCAPE
RTD #7 NAME:
Range: 8 alphanumeric characters
RTD #7 ALARM:
Off
Range: Off, Latched, Unlatched
ASSIGN ALARM
RELAYS (2-5): ---5
Range: Any combination of Relays 2 to 5.
RTD #7 ALARM
TEMPERATURE: 80°C
Range: 1 to 250°C in steps of 1
RTD #7 ALARM
EVENTS: Off
Range: On, Off
RTD #7 TRIP:
Off
Range: Off, Latched, Unlatched
RTD #7 TRIP VOTING:
RTD #7
Range: RTD #1 to RTD #12
ASSIGN TRIP
RELAYS (1-4): 1---
Range: Any combination of Relays 1 to 4
RTD #7 TRIP
TEMPERATURE: 90°C
Range: 1 to 250°C in steps of 1
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
4
RTDs 7 through 10 default to Bearing RTD type. There are individual alarm and trip configurations for each RTD. This
allows one of the RTDs to be turned off if it malfunctions. The alarm level and the trip level are normally set slightly above
the normal running temperature, but below the bearing temperature rating. Trip voting has been added for extra reliability in
the event of RTD malfunction. If enabled, a second RTD must also exceed the trip temperature of the RTD being checked
before a trip will be issued. If the RTD is chosen to vote with itself, the voting feature is disabled. Each RTD name may be
changed if desired.
GE Multilin
489 Generator Management Relay
4-51
4.9 S8 RTD TEMPERATURE
4 SETPOINTS
4.9.4 RTD 11
PATH: SETPOINTS  S8 RTD TEMPERATURE  RTD #11
ð
 RTD #11
 [ENTER] for more
ENTER
ð RTD #11 APPLICATION:
Range: Stator, Bearing, Ambient, Other, None
ESCAPE
Other
ESCAPE
RTD #11 NAME:
Range: 8 alphanumeric characters
RTD #11 ALARM:
Off
Range: Off, Latched, Unlatched
ASSIGN ALARM
RELAYS (2-5): ---5
Range: Any combination of Relays 2 to 5.
RTD #11 ALARM
TEMPERATURE: 80°C
Range: 1 to 250°C in steps of 1
RTD #11 ALARM
EVENTS: Off
Range: On, Off
RTD #11 TRIP:
Off
Range: Off, Latched, Unlatched
RTD #11 TRIP VOTING:
RTD #11
Range: RTD #1 to RTD #12
ASSIGN TRIP
RELAYS (1-4): 1---
Range: Any combination of Relays 1 to 4
RTD #11 TRIP
TEMPERATURE: 90°C
Range: 1 to 250°C in steps of 1
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
4
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
RTD 11 defaults to Other RTD type. The Other selection allows the RTD to be used to monitor any temperature that might
be required, either for a process or additional bearings or other. There are individual alarm and trip configurations for this
RTD. Trip voting has been added for extra reliability in the event of RTD malfunction. If enabled, a second RTD must also
exceed the trip temperature of the RTD being checked before a trip will be issued. If the RTD is chosen to vote with itself,
the voting feature is disabled. The RTD name may be changed if desired.
4-52
489 Generator Management Relay
GE Multilin
4 SETPOINTS
4.9 S8 RTD TEMPERATURE
4.9.5 RTD 12
PATH: SETPOINTS  S8 RTD TEMPERATURE  RTD #12
ð
 RTD #12
 [ENTER] for more
ENTER
ð RTD #12 APPLICATION:
Range: Stator, Bearing, Ambient, Other, None
ESCAPE
Ambient
ESCAPE
RTD #12 NAME:
Range: 8 alphanumeric characters
RTD #12 ALARM:
Off
Range: Off, Latched, Unlatched
ASSIGN ALARM
RELAYS (2-5): ---5
Range: Any combination of Relays 2 to 5.
RTD #12 ALARM
TEMPERATURE: 60°C
Range: 1 to 250°C in steps of 1
RTD #12 ALARM
EVENTS: Off
Range: On, Off
RTD #12 TRIP:
Off
Range: Off, Latched, Unlatched
RTD #12 TRIP VOTING:
RTD #12
Range: RTD #1 to RTD #12
ASSIGN TRIP
RELAYS (1-4): 1---
Range: Any combination of Relays 1 to 4
RTD #12 TRIP
TEMPERATURE: 80°C
Range: 1 to 250°C in steps of 1
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
4
RTDs 12 defaults to Ambient RTD type. The Ambient selection allows the RTD to be used to monitor ambient temperature.
There are individual alarm and trip configurations for this RTD. Trip voting has been added for extra reliability in the event of
RTD malfunction. If enabled, a second RTD must also exceed the trip temperature of the RTD being checked before a trip
will be issued. If the RTD is chosen to vote with itself, the voting feature is disabled. The RTD name may be changed if
desired.
GE Multilin
489 Generator Management Relay
4-53
4.9 S8 RTD TEMPERATURE
4 SETPOINTS
4.9.6 OPEN RTD SENSOR
SETPOINTS  S8 RTD TEMPERATURE  OPEN RTD SENSOR
ð
 OPEN RTD SENSOR
 [ENTER] for more
ENTER
ð OPEN RTD SENSOR:
Range: Off, Latched, Unlatched
ESCAPE
Off
ESCAPE
ASSIGN ALARM
RELAYS (2-5): ---5
Range: Any combination of Relays 2 to 5
OPEN RTD SENSOR
ALARM EVENTS: Off
Range: On, Off
MESSAGE
ESCAPE
MESSAGE
The 489 has an Open RTD Sensor Alarm. This alarm will look at all RTDs that have either an alarm or trip programmed and
determine if an RTD connection has been broken. Any RTDs that do not have a trip or alarm associated with them will be
ignored for this feature. When a broken sensor is detected, the assigned output relay will operate and a message will
appear on the display identifying the RTD that is broken. It is recommended that if this feature is used, the alarm be programmed as latched so that intermittent RTDs are detected and corrective action may be taken.
PATH: SETPOINTS  S8 RTD TEMPERATURE  RTD SHORT/LOW TEMP
 RTD SHORT/LOW TEMP
 [ENTER] for more
ð
4
4.9.7 RTD SHORT/LOW TEMPERATURE
ENTER
ð RTD SHORT/LOW TEMP
Range: Off, Latched, Unlatched
ESCAPE
ALARM: Off
ESCAPE
ASSIGN ALARM
RELAYS (2-5): ---5
Range: Any combination of Relays 2 to 5
RTD SHORT/LOW TEMP
ALARM EVENTS: Off
Range: On, Off
MESSAGE
ESCAPE
MESSAGE
The 489 has an RTD Short/Low Temperature alarm. This alarm will look at all RTDs that have either an alarm or trip programmed and determine if an RTD has either a short or a very low temperature (less than –50°C). Any RTDs that do not
have a trip or alarm associated with them will be ignored for this feature. When a short/low temperature is detected, the
assigned output relay will operate and a message will appear on the display identifying the RTD that caused the alarm. It is
recommended that if this feature is used, the alarm be programmed as latched so that intermittent RTDs are detected and
corrective action may be taken.
4-54
489 Generator Management Relay
GE Multilin
4 SETPOINTS
4.10 S9 THERMAL MODEL
4.10S9 THERMAL MODEL
4.10.1 489 THERMAL MODEL
The thermal model of the 489 is primarily intended for induction generators, especially those that start on the system bus in
the same manner as induction motors. However, some of the thermal model features may be used to model the heating
that occurs in synchronous generators during overload conditions.
One of the principle enemies of generator life is heat. Generator thermal limits are dictated by the design of both the stator
and the rotor. Induction generators that start on the system bus have three modes of operation: locked rotor or stall (when
the rotor is not turning), acceleration (when the rotor is coming up to speed), and generating (when the rotor turns at supersynchronous speed). Heating occurs in the generator during each of these conditions in very distinct ways. Typically, during
the generator starting, locked rotor and acceleration conditions, the generator will be rotor limited. That is to say that the
rotor will approach its thermal limit before the stator. Under locked rotor conditions, voltage is induced in the rotor at line frequency, 50 or 60 Hz. This voltage causes a current to flow in the rotor, also at line frequency, and the heat generated (I2R)
is a function of the effective rotor resistance. At 50 or 60 Hz, the reactance of the rotor cage causes the current to flow at
the outer edges of the rotor bars. The effective resistance of the rotor is therefore at a maximum during a locked rotor condition as is rotor heating. When the generator is running at above rated speed, the voltage induced in the rotor is at a low
frequency (approximately 1 Hz) and therefore, the effective resistance of the rotor is reduced quite dramatically. During
overloads, the generator thermal limit is typically dictated by stator parameters. Some special generators might be all stator
or all rotor limited. During acceleration, the dynamic nature of the generator slip dictates that rotor impedance is also
dynamic, and a third thermal limit characteristic is necessary.
The figure below illustrates typical thermal limit curves for induction motors. The starting characteristic is shown for a high
inertia load at 80% voltage. If the machine started quicker, the distinct characteristics of the thermal limit curves would not
be required and the running overload curve would be joined with locked rotor safe stall times to produce a single overload
curve.
The generator manufacturer should provide a safe stall time or thermal limit curves for any generator that is started as an
induction motor. These thermal limits are intended to be used as guidelines and their definition is not always precise. When
operation of the generator exceeds the thermal limit, the generator insulation does not immediately melt, rather, the rate of
insulation degradation reaches a point where continued operation will significantly reduce generator life.
400
HIGH
INERTIA
MOTOR
300
200
RUNNING OVERLOAD
100
80
A,B,AND C ARE THE
ACCELERATION THERMAL LIMIT
CURVES AT 100%, 90%, AND
80%VOLTAGE, REPECTIVELY
TIME-SECONDS
60
40
C
B
20
A
G
F
10
8
E
6
4
E,F, AND G ARE THE
SAFE STALL THERMAL LIMIT
TIMES AT 100%, 90%, AND
80%VOLTAGE, REPECTIVELY
2
1
0
100
200
300
400
500
600
% CURRENT
806827A1.CDR
Figure 4–10: TYPICAL TIME-CURRENT AND THERMAL LIMIT CURVES (ANSI/IEEE C37.96)
GE Multilin
489 Generator Management Relay
4-55
4
4.10 S9 THERMAL MODEL
4 SETPOINTS
4.10.2 MODEL SETUP
a) DESCRIPTION
PATH: SETPOINTS  S9 THERMAL MODEL  MODEL SETUP
ð
 MODEL SETUP
 [ENTER] for more
ENTER
Range: No, Yes
MODEL: No
ESCAPE
OVERLOAD PICKUP
LEVEL: 1.01 x FLA
Range: 1.01 to 1.25 × FLA in steps of 0.01
UNBALANCE BIAS
K FACTOR
Range: 0 to 12 in steps of 1
A value of "0" effectively defeats this feature
COOL TIME CONSTANT
ONLINE: 15 min.
Range: 0 to 500 min. in steps of 1
COOL TIME CONSTANT
OFFLINE: 30 min.
Range: 0 to 500 min. in steps of 1
HOT/COLD SAFE
STALL RATIO: 1.00
Range: 0.01 to 1.00 in steps of 0.01
ENABLE RTD
BIASING: No
Range: No, Yes
RTD BIAS
MINIMUM: 40°C
Range: 0 to 250°C in steps of 1
Seen only if ENABLE RTD BIASING is "Yes"
RTD BIAS CENTER
POINT: 130°C
Range: 0 to 250°C in steps of 1
Seen only if ENABLE RTD BIASING is "Yes"
RTD BIAS
MAXIMUM: 155°C
Range: 0 to 250°C in steps of 1
Seen only if ENABLE RTD BIASING is "Yes"
SELECT CURVE STYLE:
Standard
Range: Standard, Custom, Voltage Dependent
STANDARD OVERLOAD
CURVE NUMBER: 4
Range: 1 to 15 in steps of 1. Seen only if SELECT
CURVE STYLE is "Standard"
TIME TO TRIP AT
1.01 x FLA: 17414.5 s
Range: 0.5 to 99999.9 in steps of 0.1. Seen only if
SELECT CURVE STYLE is "Standard"
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
4
ð ENABLE THERMAL
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
↓
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
4-56
TIME TO TRIP AT
20.0 x FLA: 20.0 x FLA
Range: 0.5 to 99999.9 in steps of 0.1. Seen only if
SELECT CURVE STYLE is "Standard"
MINIMUM ALLOWABLE
VOLTAGE: 80%
Range: 70 to 95% in steps of 1. Seen only if SELECT
CURVE STYLE is "Voltage Dependent"
STALL CURRENT @ MIN
VOLTAGE: 4.80 x FLA
Range: 2.00 to 15.00 × FLA in steps of 0.01.Seen only if
SELECT CURVE STYLE is Voltage Dependent
SAFE STALL TIME @
MIN VOLTAGE: 20.0 s
Range: 0.5 to 999.9 in steps of 0.1. Seen only if SELECT
CURVE STYLE is "Voltage Dependent"
ACCEL. INTERSECT @
MIN VOLT: 3.80 x FLA
Range: 2.00 to STALL CURRENT @ MIN VOLTAGE in
steps of 0.01. Seen only if SELECT CURVE
STYLE is "Voltage Dependent"
STALL CURRENT @ 100%
VOLTAGE: 6.00 x FLA
Range: 2.00 to 15.00 × FLA in steps of 0.01. Seen only if
SELECT CURVE STYLE is Voltage Dependent
SAFE STALL TIME @
100% VOLTAGE: 10.0 s
Range: 0.5 to 999.9 in steps of 0.1. Seen only if SELECT
CURVE STYLE is "Voltage Dependent"
489 Generator Management Relay
GE Multilin
4 SETPOINTS
4.10 S9 THERMAL MODEL
ESCAPE
MESSAGE
ACCEL. INTERSECT @
100% VOLT: 5.00 x FLA
Range: 2.00 to STALL CURRENT @ 100% VOLTAGE in
steps of 0.01. Seen only if SELECT CURVE
STYLE is "Voltage Dependent"
The current measured at the output CTs is used for the thermal model. The thermal model consists of five key elements:
the overload curve and overload pickup level, the unbalance biasing of the generator current while the machine is running,
the cooling time constants, and the biasing of the thermal model based on hot/cold generator information and measured
stator temperature. Each of these elements are described in detail in the sections that follow.
Generator Rated MVA
The generator FLA is calculated as: ---------------------------------------------------------------------------------------------------------------------3 × Rated Generator Phase-Phase Voltage
NOTE
(EQ 4.26)
The 489 integrates both stator and rotor heating into one model. Machine heating is reflected in a register called Thermal
Capacity Used. If the machine has been stopped for a long period of time, it will be at ambient temperature and thermal
capacity used should be zero. If the machine is in overload, once the thermal capacity used reaches 100%, a trip will occur.
The overload curve accounts for machine heating during stall, acceleration, and running in both the stator and the rotor.
The Overload Pickup setpoint defines where the running overload curve begins as the generator enters an overload condition. This is useful to accommodate a service factor. The curve is effectively cut off at current values below this pickup.
Generator thermal limits consist of three distinct parts based on the three conditions of operation, locked rotor or stall,
acceleration, and running overload. Each of these curves may be provided for both a hot and cold machine. A hot machine
is defined as one that has been running for a period of time at full load such that the stator and rotor temperatures have settled at their rated temperature. A cold machine is defined as a machine that has been stopped for a period of time such that
the stator and rotor temperatures have settled at ambient temperature. For most machines, the distinct characteristics of
the thermal limits are formed into one smooth homogeneous curve. Sometimes only a safe stall time is provided. This is
acceptable if the machine has been designed conservatively and can easily perform its required duty without infringing on
the thermal limit. In this case, the protection can be conservative. If the machine has been designed very close to its thermal limits when operated as required, then the distinct characteristics of the thermal limits become important.
The 489 overload curve can take one of three formats, Standard, Custom Curve, or Voltage Dependent. Regardless of
which curve style is selected, the 489 will retain thermal memory in the form of a register called Thermal Capacity Used.
This register is updated every 50 ms using the following equation:
TC used t = TC used
where:
t – 50ms
50 ms
+ ---------------------------- × 100%
time to trip
(EQ 4.27)
time to trip = time taken from the overload curve at Ieq as a function of FLA.
The overload protection curve should always be set slightly lower than the thermal limits provided by the manufacturer. This
will ensure that the machine is tripped before the thermal limit is reached. If the starting times are well within the safe stall
times, it is recommended that the 489 Standard Overload Curve be used. The standard overload curves are a series of 15
curves with a common curve shape based on typical generator thermal limit curves (see the following figure and table).
When the generator trips offline due to overload the generator will be locked out (the trip relay will stay latched) until generator thermal capacity reaches below 15%.
GE Multilin
489 Generator Management Relay
4-57
4
4.10 S9 THERMAL MODEL
4 SETPOINTS
100000
10000
TIME IN SECONDS
4
1000
100
x15
10
x1
1.00
0.10
1.00
10
100
MULTIPLE OF FULL LOAD AMPS
1000
806804A5.CDR
Figure 4–11: 489 STANDARD OVERLOAD CURVES
4-58
489 Generator Management Relay
GE Multilin
4 SETPOINTS
4.10 S9 THERMAL MODEL
Table 4–7: 489 STANDARD OVERLOAD CURVE MULTIPLIERS
PICKUP
LEVEL
STANDARD CURVE MULTIPLIERS
×1
×2
×3
×4
×5
×6
×7
×8
×9
× 10
× 11
× 12
× 13
× 14
× 15
13061
17414
21768
26122
30475
34829
39183
43536
47890
52243
56597
60951
65304
1.01
4353.6 8707.2
1.05
853.71 1707.4 2561.1
3414.9 4268.6 5122.3
5976.0
6829.7
7683.4
8537.1
9390.8
10245
11098
11952
12806
1.10
416.68 833.36 1250.0
1666.7 2083.4 2500.1
2916.8
3333.5
3750.1
4166.8
4583.5
5000.2
5416.9
5833.6
6250.2
2982.9
1.20
198.86 397.72 596.58
795.44 994.30
1193.2
1392.0
1590.9
1789.7
1988.6
2187.5
2386.3
2585.2
2784.1
1.30
126.80 253.61 380.41
507.22 634.02 760.82
887.63
1014.4
1141.2
1268.0
1394.8
1521.6
1648.5
1775.3
1902.1
1.40
91.14
182.27 273.41
364.55 455.68 546.82
637.96
729.09
820.23
911.37
1002.5
1093.6
1184.8
1275.9
1367.0
1.50
69.99
139.98 209.97
279.96 349.95 419.94
489.93
559.92
629.91
699.90
769.89
839.88
909.87
979.86
1049.9
1.75
42.41
84.83
127.24
169.66 212.07 254.49
296.90
339.32
381.73
424.15
466.56
508.98
551.39
593.81
636.22
2.00
29.16
58.32
87.47
116.63
145.79 174.95
204.11
233.26
262.42
291.58
320.74
349.90
379.05
408.21
437.37
2.25
21.53
43.06
64.59
86.12
107.65 129.18
150.72
172.25
193.78
215.31
236.84
258.37
279.90
301.43
322.96
2.50
16.66
33.32
49.98
66.64
83.30
99.96
116.62
133.28
149.94
166.60
183.26
199.92
216.58
233.24
249.90
2.75
13.33
26.65
39.98
53.31
66.64
79.96
93.29
106.62
119.95
133.27
146.60
159.93
173.25
186.58
199.91
3.00
10.93
21.86
32.80
43.73
54.66
65.59
76.52
87.46
98.39
109.32
120.25
131.19
142.12
153.05
163.98
3.25
9.15
18.29
27.44
36.58
45.73
54.87
64.02
73.16
82.31
91.46
100.60
109.75
118.89
128.04
137.18
3.50
7.77
15.55
23.32
31.09
38.87
46.64
54.41
62.19
69.96
77.73
85.51
93.28
101.05
108.83
116.60
3.75
6.69
13.39
20.08
26.78
33.47
40.17
46.86
53.56
60.25
66.95
73.64
80.34
87.03
93.73
100.42
4.00
5.83
11.66
17.49
23.32
29.15
34.98
40.81
46.64
52.47
58.30
64.13
69.96
75.79
81.62
87.45
4.25
5.12
10.25
15.37
20.50
25.62
30.75
35.87
41.00
46.12
51.25
56.37
61.50
66.62
71.75
76.87
4.50
4.54
9.08
13.63
18.17
22.71
27.25
31.80
36.34
40.88
45.42
49.97
54.51
59.05
63.59
68.14
4.75
4.06
8.11
12.17
16.22
20.28
24.33
28.39
32.44
36.50
40.55
44.61
48.66
52.72
56.77
60.83
5.00
3.64
7.29
10.93
14.57
18.22
21.86
25.50
29.15
32.79
36.43
40.08
43.72
47.36
51.01
54.65
5.50
2.99
5.98
8.97
11.96
14.95
17.94
20.93
23.91
26.90
29.89
32.88
35.87
38.86
41.85
44.84
6.00
2.50
5.00
7.49
9.99
12.49
14.99
17.49
19.99
22.48
24.98
27.48
29.98
32.48
34.97
37.47
6.50
2.12
4.24
6.36
8.48
10.60
12.72
14.84
16.96
19.08
21.20
23.32
25.44
27.55
29.67
31.79
7.00
1.82
3.64
5.46
7.29
9.11
10.93
12.75
14.57
16.39
18.21
20.04
21.86
23.68
25.50
27.32
7.50
1.58
3.16
4.75
6.33
7.91
9.49
11.08
12.66
14.24
15.82
17.41
18.99
20.57
22.15
23.74
8.00
1.39
2.78
4.16
5.55
6.94
8.33
9.71
11.10
12.49
13.88
15.27
16.65
18.04
19.43
20.82
10.00
1.39
2.78
4.16
5.55
6.94
8.33
9.71
11.10
12.49
13.88
15.27
16.65
18.04
19.43
20.82
15.00
1.39
2.78
4.16
5.55
6.94
8.33
9.71
11.10
12.49
13.88
15.27
16.65
18.04
19.43
20.82
20.00
1.39
2.78
4.16
5.55
6.94
8.33
9.71
11.10
12.49
13.88
15.27
16.65
18.04
19.43
20.82
Above 8.0 × Pickup, the trip time for 8.0 is used. This prevents the overload curve from acting as an instantaneous element.
NOTE
The standard overload curves equation is:
Curve Multiplier × 2.2116623
Time to Trip = ---------------------------------------------------------------------------------------------------------------------------------------------------2
0.02530337 × ( Pickup – 1 ) + 0.05054758 × ( Pickup – 1 )
GE Multilin
489 Generator Management Relay
(EQ 4.28)
4-59
4
4.10 S9 THERMAL MODEL
4 SETPOINTS
b) CUSTOM OVERLOAD CURVE
If the induction generator starting current begins to infringe on the thermal damage curves, it may become necessary to use
a custom curve to tailor generator protection so successful starting may be possible without compromising protection. Furthermore, the characteristics of the starting thermal (locked rotor and acceleration) and the running thermal damage curves
may not fit together very smoothly. In this instance, it may be necessary to use a custom curve to tailor protection to the
thermal limits to allow the generator to be started successfully and utilized to its full potential without compromising protection. The distinct parts of the thermal limit curves now become more critical. For these conditions, it is recommended that
the 489 custom curve thermal model be used. The custom overload curve allows users to program their own curves by
entering trip times for 30 pre-determined current levels.
The curves below show that if the running overload thermal limit curve were smoothed into one curve with the locked rotor
thermal limit curve, the induction generator could not be started at 80% voltage. A custom curve is required.
489
TYPICAL CUSTOM CURVE
GE Multilin
10000
1
4
1000
PROGRAMMED 469 CUSTOM CURVE
2
RUNNING SAFETIME (STATOR LIMIT)
3
ACCELERATION SAFETIME (ROTOR LIMIT)
4
MACHINE CURRENT @ 100% VOLTAGE
5
MACHINE CURRENT @ 80% VOLTAGE
TIME TO TRIP IN SECONDS
1
2
100
3
10
4
5
MULTIPLE OF FULL LOAD CURRENT SETPOINT
1000
100
10
0.5
0.1
1
1.0
808825A3.CDR
Figure 4–12: CUSTOM CURVE EXAMPLE
4-60
489 Generator Management Relay
GE Multilin
4 SETPOINTS
4.10 S9 THERMAL MODEL
c) VOLTAGE DEPENDENT OVERLOAD CURVE
It is possible and acceptable that the acceleration time exceeds the safe stall time (bearing in mind that a locked rotor condition is quite different than an acceleration condition). In this instance, each distinct portion of the thermal limit curve must
be known and protection coordinated against that curve. The protection relay must be able to distinguish between a locked
rotor condition, an accelerating condition, and a running condition. The 489 voltage dependent overload curve feature is tailored to protect these types of machines. Voltage is monitored constantly during starting and the acceleration thermal limit
curve adjusted accordingly. If the VT Connection setpoint is set to none or if a VT fuse failure is detected, the acceleration
thermal limit curve for the minimum allowable voltage will be used.
The voltage dependent overload curve is comprised of the three characteristic thermal limit curve shapes determined by
the stall or locked rotor condition, acceleration, and running overload. The curve is constructed by entering a custom curve
shape for the running overload protection curve. Next, a point must be entered for the acceleration protection curve at the
point of intersection with the custom curve, based on the minimum allowable starting voltage as defined by the minimum
allowable voltage. Locked Rotor Current and safe stall time must also be entered for that voltage. A second point of intersection must be entered for 100% voltage. Once again, the locked rotor current and the safe stall time must be entered, this
time for 100% voltage. The protection curve that is created from the safe stall time and intersection point will be dynamic
based on the measured voltage between the minimum allowable voltage and the 100% voltage. This method of protection
inherently accounts for the change in speed as an impedance relay would. The change in impedance is reflected by
machine terminal voltage and line current. For any given speed at any given voltage, there is only one value of line current.
GE Multilin
1000
900
800
700
1- Running Overload Thermal Limit
2- Acceleration Thermal Limit @ 80%V
3- Acceleration Thermal Limit @ 100%V
4- Locked Rotor Thermal Limit
5- Machine Acceleration Curve @ 80% V
6- Machine Acceleration Curve @ 100%V
1
600
4
489
THERMAL LIMITS
FOR HIGH INERTIAL LOAD
500
400
300
2
200
TIME TO TRIP (SECONDS)
3
100
90
80
70
60
50
40
30
20
10
9
8
7
6
4
5
4
5
3
6
2
1
1
2
3
4
5
6
MULTIPLES OF FULL LOAD AMPS
7
8
808826A3.CDR
Figure 4–13: THERMAL LIMITS FOR HIGH INERTIAL LOAD
GE Multilin
489 Generator Management Relay
4-61
4.10 S9 THERMAL MODEL
4 SETPOINTS
To illustrate the Voltage Dependent Overload Curve feature, the thermal limits shown in Figure 4–13: Thermal Limits for
High Inertial Load on page 4–61 will be used.
1.
Construct a custom curve for the running overload thermal limit. If the curve does not extend to the acceleration thermal limits, extend it such that the curve intersects the acceleration thermal limit curves. (see CUSTOM CURVE below).
2.
Enter the per unit current value for the acceleration overload curve intersect with the custom curve for 80% voltage.
Also enter the per unit current and safe stall protection time for 80% voltage (see ACCELERATION CURVE below).
3.
Enter the per unit current value for the acceleration overload curve intersect with the custom curve for 100% voltage.
Also enter the per unit current and safe stall protection time for 100% voltage (see ACCELERATION CURVE below)
GE Multilin
4
489
VOLTAGE DEPENDENT OVERLOAD
(CUSTOM CURVE)
GE Multilin
1000
900
800
700
1000
900
800
700
600
600
500
500
400
400
300
489
VOLTAGE DEPENDENT OVERLOAD
(ACCELERATION CURVES)
489 Custom Curve
300
Acceleration Intersect at 80%V
200
200
TIME TO TRIP (SECONDS)
TIME TO TRIP (SECONDS)
Acceleration Intersect at 100%V
100
90
80
70
60
50
40
30
20
100
90
80
70
60
50
40
30
20
10
9
8
7
6
10
9
8
7
6
5
5
4
4
3
3
2
2
1
1
1
2
3
4
5
6
MULTIPLES OF FULL LOAD AMPS
7
8
1
2
808827A3.CDR
3
4
5
6
MULTIPLES OF FULL LOAD AMPS
7
8
808828A3.CDR
Figure 4–14: VOLTAGE DEPENDENT OVERLOAD CURVES
4-62
489 Generator Management Relay
GE Multilin
4 SETPOINTS
4.10 S9 THERMAL MODEL
The 489 takes the information provided and create protection curves for any voltage between the minimum and 100%. For
values above the voltage in question, the 489 extrapolates the safe stall protection curve to 110% voltage. This current level
is calculated by taking the locked rotor current at 100% voltage and multiplying by 1.10. For trip times above the 110% current level, the trip time of 110% will be used (see the figure below).
489
VOLTAGE DEPENDENT
OVERLOAD PROTECTION CURVES
GE Multilin
1000
900
800
700
600
Custom Curve
500
400
300
Acceleration Intersect at 80%V
4
200
TIME TO TRIP (SECONDS)
Acceleration Intersect at 100%V
100
90
80
70
60
50
40
30
Safe Stall Time at 80%V,
80%V Stall Current
20
Safe Stall Time at 100%V,
100%V Stall Current
10
9
8
7
6
5
Safe Stall Points
Extrapolated to 110%V
4
3
2
1
1
2
3
4
5
MULTIPLES OF FULL LOAD AMPS
6
8
7
808831A3.CDR
Figure 4–15: VOLTAGE DEPENDENT OVERLOAD PROTECTION CURVES
The safe stall curve is in reality a series of safe stall points for different voltages. For a given voltage, there can be
only one value of stall current, and therefore only one safe stall time.
NOTE
GE Multilin
489 Generator Management Relay
4-63
4.10 S9 THERMAL MODEL
4 SETPOINTS
The following curves illustrate the resultant overload protection for 80% and 100% voltage, respectively. For voltages inbetween these levels, the 489 shifts the acceleration curve linearly and constantly based upon the measured voltage during
generator start.
1000
900
800
700
600
600
500
500
400
400
300
300
200
200
100
90
80
70
60
100
90
80
70
60
50
40
30
20
489
VOLTAGE DEPENDENT
OVERLOAD PROTECTION at 100% V
GE Multilin
1000
900
800
700
TIME TO TRIP (SECONDS)
4
TIME TO TRIP (SECONDS)
GE Multilin
489
VOLTAGE DEPENDENT
OVERLOAD PROTECTION at 80% V
50
40
30
20
10
9
8
7
6
10
9
8
7
6
5
5
4
4
3
3
2
2
1
1
1
2
3
4
5
6
MULTIPLES OF FULL LOAD AMPS
7
8
1
2
808830A3.CDR
3
4
5
6
MULTIPLES OF FULL LOAD AMPS
7
8
808829A3.CDR
Figure 4–16: VOLTAGE DEPENDENT O/L PROTECTION AT 80% AND 100% VOLTAGE
4-64
489 Generator Management Relay
GE Multilin
4 SETPOINTS
4.10 S9 THERMAL MODEL
d) UNBALANCE BIAS
Unbalanced phase currents will cause additional rotor heating that will not be accounted for by electromechanical relays
and may not be accounted for in some electronic protective relays. When the generator is running, the rotor will rotate in the
direction of the positive sequence current at near synchronous speed. Negative sequence current, which has a phase rotation that is opposite to the positive sequence current, and hence, opposite to the rotor rotation, will generate a rotor voltage
that will produce a substantial rotor current. This induced current will have a frequency that is approximately twice the line
frequency, 100 Hz for a 50 Hz system or 120 Hz for a 60 Hz system. Skin effect in the rotor bars at this frequency will cause
a significant increase in rotor resistance and therefore, a significant increase in rotor heating. This extra heating is not
accounted for in the thermal limit curves supplied by the generator manufacturer as these curves assume positive
sequence currents only that come from a perfectly balanced supply and generator design.
The 489 measures the ratio of negative to positive sequence current. The thermal model may be biased to reflect the additional heating that is caused by negative sequence current when the machine is running. This biasing is done by creating
an equivalent heating current rather than simply using average current (Iper_unit). This equivalent current is calculated using
the equation shown below.
I eq =
where:
2
I 1 + kI 2
2
(EQ 4.29)
Ieq = equivalent motor heating current in per unit (based on FLA)
I2= negative-sequence current in per unit (based on FLA)
I1= positive-sequence current in per unit (based on FLA)
k = constant relating negative-sequence rotor resistance to positive-sequence rotor resistance, not to be confused
with the k indicating generator negative-sequence capability for an inverse time curve.
1.05
1.05
1.00
1.00
DERATING FACTOR
DERATING FACTOR
The figure below shows induction machine derating as a function of voltage unbalance as recommended by NEMA
(National Electrical Manufacturers Association). Assuming a typical inrush of 6 × FLA and a negative sequence impedance
of 0.167, voltage unbalances of 1, 2, 3, 4, and 5% equal current unbalances of 6, 12, 18, 24, and 30%, respectively. Based
on this assumption, the GE curve illustrates the amount of machine derating for different values of k entered for the UNBALANCE BIAS K FACTOR setpoint. Note that the curve created when k = 8 is almost identical to the NEMA derating curve.
0.95
0.90
0.85
0.80
0.95
k=2
0.90
0.85
k=4
0.80
k=6
0.75
0.75
0.70
0.70
0
1
2
3
4
5
k=8
k=10
0
PERCENT VOLTAGE UNBALANCE
NEMA
1
2
3
4
5
PERCENT VOLTAGE UNBALANCE
GE MULTILIN
808728A1.CDR
If a k value of 0 is entered, the unbalance biasing is defeated and the overload curve will time out against the measured per
unit motor current. k may be calculated conservatively as:
175
- (typical estimate); k = 230
---------- (conservative estimate), where I LR is the per unit locked rotor current
k = --------2
2
I LR
I LR
GE Multilin
489 Generator Management Relay
(EQ 4.30)
4-65
4
4.10 S9 THERMAL MODEL
4 SETPOINTS
e) MACHINE COOLING
The 489 thermal capacity used value is reduced exponentially when the motor current is below the OVERLOAD PICKUP setpoint. This reduction simulates machine cooling. The cooling time constants should be entered for both stopped and running cases (the generator is assumed to be running if current is measured or the generator is offline). A machine with a
stopped rotor normally cools significantly slower than one with a turning rotor. Machine cooling is calculated using the following formulae:
TC used = ( TC used_start – TC used_end ) ( e
–t ⁄ τ
) + TC used_end
(EQ 4.31)
I eq
hot
TC used_end =  -------------------------------------------  1 – ----------- × 100%
overload_pickup
cold
where:
4
(EQ 4.32)
TCused
TCused_start
TCused_end
= thermal capacity used
= TCused value caused by overload condition
= TCused value dictated by the hot/cold curve ratio when the machine is running
(= 0 when the machine is stopped)
t
= time in minutes
τ
= Cool Time Constant (running or stopped)
= equivalent heating current
Ieq
overload_pickup = overload pickup setpoint as a multiple of FLA
hot / cold
= hot/cold curve ratio
100
100
75
Thermal Capacity Used
Thermal Capacity Used
75
Cool Time Constant= 15 min
TCused_start= 85%
Hot/Cold Ratio= 80%
Ieq/Overload Pickup= 80%
50
25
50
25
0
0
0
30
60
90
120
150
180
0
30
60
90
120
Time in Minutes
Time in Minutes
80% LOAD
100% LOAD
100
150
180
100
75
Thermal Capacity Used
Thermal Capacity Used
Cool Time Constant= 15 min
TCused_start= 85%
Hot/Cold Ratio= 80%
Ieq/Overload Pickup= 100%
Cool Time Constant= 30 min
TCused_start= 85%
Hot/Cold Ratio= 80%
Motor Stopped after running Rated Load
TCused_end= 0%
50
25
0
75
Cool Time Constant= 30 min
TCused_start= 100%
Hot/Cold Ratio= 80%
Motor Stopped after Overload Trip
TCused_end= 0%
50
25
0
0
30
60
90
120
150
180
0
30
60
90
120
Time in Minutes
Time in Minutes
MOTOR STOPPED
MOTOR TRIPPED
150
180
808705A1.CDR
Figure 4–17: THERMAL MODEL COOLING
4-66
489 Generator Management Relay
GE Multilin
4 SETPOINTS
4.10 S9 THERMAL MODEL
f) HOT/COLD CURVE RATIO
When thermal limit information is available for both a hot and cold machine, the 489 thermal model will adapt for the conditions if the HOT/COLD CURVE RATIO is programmed. The value entered for this setpoint dictates the level of thermal capacity
used that the relay will settle at for levels of current that are below the OVERLOAD PICKUP LEVEL. When the generator is running at a level below the OVERLOAD PICKUP LEVEL, the thermal capacity used will rise or fall to a value based on the average phase current and the entered HOT/COLD CURVE RATIO. Thermal capacity used will either rise at a fixed rate of 5% per
minute or fall as dictated by the running cool time constant.
hot
TC used_end = I eq ×  1 – ----------- × 100%

cold
where:
(EQ 4.33)
TCused_end = Thermal Capacity Used if Iper_unit remains steady state
Ieq = equivalent generator heating current
hot/cold = HOT/COLD CURVE RATIO setpoint
The hot/cold curve ratio may be determined from the thermal limit curves, if provided, or the hot and cold safe stall times.
Simply divide the hot safe stall time by the cold safe stall time. If hot and cold times are not provided, there can be no differentiation and the HOT/COLD CURVE RATIO should be entered as "1.00".
g) RTD BIAS
The thermal replica created by the features described in the sections above operates as a complete and independent
model. However, the thermal overload curves are based solely on measured current, assuming a normal 40°C ambient and
normal machine cooling. If there is an unusually high ambient temperature, or if machine cooling is blocked, generator temperature will increase. If the stator has embedded RTDs, the 489 RTD bias feature should be used to correct the thermal
model.
The RTD bias feature is a two part curve, constructed using 3 points. If the maximum stator RTD temperature is below the
RTD BIAS MINIMUM setpoint (typically 40°C), no biasing occurs. If the maximum stator RTD temperature is above the RTD
BIAS MAXIMUM setpoint (typically at the stator insulation rating or slightly higher), then the thermal memory is fully biased
and thermal capacity is forced to 100% used. At values in between, the present thermal capacity used created by the overload curve and other elements of the thermal model, is compared to the RTD Bias thermal capacity used from the RTD Bias
curve. If the RTD Bias thermal capacity used value is higher, then that value is used from that point onward. The RTD BIAS
CENTER POINT should be set at the rated running temperature of the machine. The 489 automatically determines the thermal capacity used value for the center point using the HOT/COLD SAFE STALL RATIO setpoint.
hot
TC used @ RTD_Bias_Center =  1 – ----------- × 100%
cold
(EQ 4.34)
At temperatures less that the RTD_Bias_Center temperature,
Temp actual – Temp min
RTD_Bias_TC used = -------------------------------------------------------- × ( 100 – TC used @ RTD_Bias_Center ) + TC used @ RTD_Bias_Center
Temp center – Temp min
(EQ 4.35)
At temperatures greater than the RTD_Bias_Center temperature,
Temp actual – Temp center
RTD_Bias_TC used = ------------------------------------------------------------- × ( 100 – TC used @ RTD_Bias_Center ) + TC used @ RTD_Bias_Center
Temp max – Temp center
where:
(EQ 4.36)
RTD_Bias_TCused = TC used due to hottest stator RTD
Tempacutal = current temperature of the hottest stator RTD
Tempmin = RTD Bias minimum setpoint
Tempcenter = RTD Bias center setpoint
Tempmax = RTD Bias maximum setpoint
TCused @ RTD_Bias_Center = TC used defined by the HOT/COLD SAFE STALL RATIO setpoint
In simple terms, the RTD bias feature is real feedback of measured stator temperature. This feedback acts as correction of
the thermal model for unforeseen situations. Since RTDs are relatively slow to respond, RTD biasing is good for correction
and slow generator heating. The rest of the thermal model is required during high phase current conditions when machine
heating is relatively fast.
GE Multilin
489 Generator Management Relay
4-67
4
4.10 S9 THERMAL MODEL
4 SETPOINTS
It should be noted that the RTD bias feature alone cannot create a trip. If the RTD bias feature forces the thermal capacity
used to 100%, the machine current must be above the over-load pickup before an overload trip occurs. Presumably, the
machine would trip on stator RTD temperature at that time.
RTD Bias Maximum
RTD Thermal Capacity Used
100
Hot/Cold = 0.85
Rated Temperature=130°C
Insulation Rating=155°C
80
60
40
20
RTD Bias Center Point
RTD Bias Minimum
4
0
–50
0
50
100
150
200
250
Maximum Stator RTD Temperature
808721A1.CDR
Figure 4–18: RTD BIAS CURVE
4.10.3 THERMAL ELEMENTS
SETPOINTS  S9 THERMAL MODEL  THERMAL ELEMENTS
ð
 THERMAL ELEMENTS
 [ENTER] for more
ENTER
ð THERMAL MODEL
Range: Off, Latched, Unlatched
ESCAPE
ALARM: Off
ESCAPE
ASSIGN ALARM
RELAYS (2-5): ---5
Range: Any combination of Relays 2 to 5
THERMAL ALARM
LEVEL: 75% Used
Range: 10 to 100% Used in steps of 1
THERMAL MODEL
ALARM EVENTS: Off
Range: On, Off
THERMAL MODEL
TRIP: Off
Range: Off, Latched, Unlatched
ASSIGN TRIP
RELAYS (1-4): 1---
Range: Any combination of Relays 1 to 4
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
Once the thermal model is setup, an alarm and/or trip element can be enabled. If the generator has been offline for a long
period of time, it will be at ambient temperature and thermal capacity used should be zero. If the generator is in overload,
once the thermal capacity used reaches 100%, a trip will occur. The thermal model trip will remain active until a lockout time
has expired. The lockout time will be based on the reduction of thermal capacity from 100% used to 15% used. This reduction will occur at a rate defined by the stopped cooling time constant. The thermal capacity used alarm may be used as a
warning indication of an impending overload trip.
4-68
489 Generator Management Relay
GE Multilin
4 SETPOINTS
4.11 S10 MONITORING
4.11S10 MONITORING
4.11.1 TRIP COUNTER
PATH: SETPOINTS  S10 MONITORING  TRIP COUNTER
ð
 TRIP COUNTER
 [ENTER] for more
ENTER
ð TRIP COUNTER
Range: Off, Latched, Unlatched
ESCAPE
ALARM: Off
ESCAPE
ASSIGN ALARM
RELAYS (2-5): ---5
Range: Any combination of Relays 2 to 5
TRIP COUNTER ALARM
LEVEL: 25 Trips
Range: 1 to 50000 Trips in steps of 1
TRIP COUNTER ALARM
EVENTS: Off
Range: On, Off
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
When enabled, a trip counter alarm will occur when the TRIP COUNTER ALARM LEVEL is reached. The trip counter must be
cleared or the alarm level raised and the reset key must be pressed (if the alarm was latched) to reset the alarm.
For example, it might be useful to set a Trip Counter alarm at 100 trips, prompting the operator or supervisor to investigate
the type of trips that have occurred. A breakdown of trips by type may be found in the A4 MAINTENANCE  TRIP COUNTERS
actual values page. If a trend is detected, it would warrant further investigation.
4.11.2 BREAKER FAILURE
PATH: SETPOINTS  S10 MONITORING  BREAKER FAILURE
ð
 BREAKER FAILURE
 [ENTER] for more
ENTER
ð BREAKER FAILURE
Range: Off, Latched, Unlatched
ESCAPE
ALARM: Off
ESCAPE
ASSIGN ALARM
RELAYS (2-5): ---5
Range: Any combination of Relays 2 to 5
BREAKER FAILURE
LEVEL: 1.00 x CT
Range: 0.05 to 20.00 × CT in steps of 0.01
BREAKER FAILURE
DELAY: 100 ms
Range: 10 to 1000 ms in steps of 10
BREAKER FAILURE
ALARM EVENTS: Off
Range: On, Off
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
If the breaker failure alarm feature may be enabled as latched or unlatched. If the R1 Trip output relay is operated and the
generator current measured at any of the three output CTs is above the level programmed for the period of time specified
by the delay, a breaker failure alarm will occur. The time delay should be slightly longer than the breaker clearing time.
GE Multilin
489 Generator Management Relay
4-69
4
4.11 S10 MONITORING
4 SETPOINTS
4.11.3 TRIP COIL MONITOR
PATH: SETPOINTS  S10 MONITORING  TRIP COIL MONITOR
ð
 TRIP COIL MONITOR
 [ENTER] for more
ENTER
Range: Off, Latched, Unlatched
ð TRIP COIL MONITOR
ESCAPE
ALARM: Off
ESCAPE
ASSIGN ALARM
RELAYS (2-5): ---5
Range: Any combination of Relays 2 to 5
SUPERVISION OF TRIP
COIL: 52 Closed
Range: 52 Closed, 52 Open/Closed
TRIP COIL MONITOR
ALARM EVENTS: Off
Range: On, Off
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
If the trip coil monitor alarm feature is enabled as latched or unlatched, the trip coil supervision circuitry will monitor the trip
coil circuit for continuity any time that the breaker status input indicates that the breaker is closed. If that continuity is broken, a trip coil monitor alarm will occur in approximately 300 ms.
4
If 52 Open/Closed is selected, the trip coil supervision circuitry monitors the trip coil circuit for continuity at all times regardless of breaker state. This requires an alternate path around the 52a contacts in series with the trip coil when the breaker is
open. See the figure below for modifications to the wiring and proper resistor selection. If that continuity is broken, a Starter
Failure alarm will indicate Trip Coil Supervision.
TRIP COIL
SUPERVISION
E11
R1 TRIP
CONTACT
E2
F11
F1
TRIP COIL
SUPERVISION
E11
R1 TRIP
CONTACT
E2
F11
F1
TRIP COIL
SUPERVISION
E11
R1 TRIP
CONTACT
E2
F11
F1
52a
TRIP
COIL
TRIP COIL CLOSED SUPERVISION
"52 Closed"
TRIP COIL
OPEN/CLOSED
SUPERVISION
"52 Open/Closed"
WITH MULTIPLE
BREAKER AUX
CONTACTS
52a
52a
TRIP
COIL
TRIP
COIL
52a
TRIP COIL OPEN/CLOSED SUPERVISION
"52 Open/Closed"
VALUE OF RESISTOR 'R'
808727A1.CDR
SUPPLY
OHMS
WATTS
48 VDC
10 K
2
125 VDC
25 K
5
250 VDC
50 K
5
Figure 4–19: TRIP COIL SUPERVISION
4-70
489 Generator Management Relay
GE Multilin
4 SETPOINTS
4.11 S10 MONITORING
4.11.4 VT FUSE FAILURE
PATH: SETPOINTS  S10 MONITORING  VT FUSE FAILURE
ð
 VT FUSE FAILURE
 [ENTER] for more
ENTER
Range: Off, Latched, Unlatched
ð VT FUSE FAILURE
ESCAPE
ALARM: Off
ESCAPE
ASSIGN ALARM
RELAYS (2-5): ---5
Range: Any combination of Relays 2 to 5
VT FUSE FAILURE
ALARM EVENTS: Off
Range: On, Off
MESSAGE
ESCAPE
MESSAGE
A fuse failure is detected when there are significant levels of negative sequence voltage without corresponding levels of
negative sequence current measured at the output CTs. Also, if the generator is online and there is not significant positive
sequence voltage, it could indicate that all VT fuses have been pulled or the VTs are racked out. If the alarm is enabled and
a VT fuse failure detected, elements that could nuisance operation are blocked and an alarm occurs. These blocked elements include voltage restraint for the phase overcurrent, undervoltage, phase reversal, and all power elements.
I2 / I1 < 20%
V2 / V1 > 25%
I1 > 0.075 x CT
4
99ms
AND
0
V1 > 0.05 x Full Scale
Breaker Status = Online
OR
99ms
V1 < 0.05 × Full Scale
Block
Appropriate
Elements
&
Operate
Alarm
Relay
AND
0
Figure 4–20: VT FUSE FAILURE LOGIC
GE Multilin
489 Generator Management Relay
4-71
4.11 S10 MONITORING
4 SETPOINTS
4.11.5 CURRENT, MW, MVAR, AND MVA DEMAND
PATH: SETPOINTS  S10 MONITORING  CURRENT DEMAND...
ð
 CURRENT DEMAND
 [ENTER] for more
ENTER
ESCAPE
CURRENT DEMAND
ALARM: Off
Range: Off, Latched, Unlatched
ASSIGN ALARM
RELAYS (2-5): ---5
Range: Any combination of Relays 2 to 5
CURRENT DEMAND
LIMIT: 1.25 x FLA
Range: 0.10 to 20.00 × FLA in steps of 0.01
CURRENT DEMAND
ALARM EVENTS: Off
Range: On, Off
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ð
ENTER
ESCAPE
MW DEMAND
ALARM: Off
Range: Off, Latched, Unlatched
ASSIGN ALARM
RELAYS (2-5): ---5
Range: Any combination of Relays 2 to 5
MW DEMAND
LIMIT: 1.25 x Rated
Range: 0.10 to 20.00 × Rated in steps of 0.01
MW DEMAND
ALARM EVENTS: Off
Range: On, Off
ESCAPE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ENTER
Range: 5 to 90 min. in steps of 1
PERIOD: 15 min.
ESCAPE
Mvar DEMAND
ALARM: Off
Range: Off, Latched, Unlatched
ASSIGN ALARM
RELAYS (2-5): ---5
Range: Any combination of Relays 2 to 5
Mvar DEMAND
LIMIT: 1.25 x Rated
Range: 0.10 to 20.00 × Rated in steps of 0.01
Mvar DEMAND
ALARM EVENTS: Off
Range: On, Off
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ENTER
ð MVA DEMAND
Range: 5 to 90 min. in steps of 1
ESCAPE
PERIOD: 15 min.
ESCAPE
MVA DEMAND
ALARM: Off
Range: Off, Latched, Unlatched
ASSIGN ALARM
RELAYS (2-5): ---5
Range: Any combination of Relays 2 to 5
MVA DEMAND
LIMIT: 1.25 x Rated
Range: 0.10 to 20.00 × Rated in steps of 0.01
MVA DEMAND
ALARM EVENTS: Off
Range: On, Off
ð
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
4-72
ð Mvar DEMAND
ESCAPE
MESSAGE
 MVA DEMAND
 [ENTER] for more
Range: 5 to 90 min. in steps of 1
PERIOD: 15 min.
MESSAGE
 Mvar DEMAND
 [ENTER] for more
ð MW DEMAND
ESCAPE
MESSAGE
ð
4
Range: 5 to 90 min. in steps of 1
PERIOD: 15 min.
MESSAGE
 MW DEMAND
 [ENTER] for more
ð CURRENT DEMAND
ESCAPE
489 Generator Management Relay
GE Multilin
4 SETPOINTS
4.11 S10 MONITORING
The 489 can measure the demand of the generator for several parameters (current, MW, Mvar, MVA). The demand values
of generators may be of interest for energy management programs where processes may be altered or scheduled to
reduce overall demand on a feeder. The generator FLA is calculated as:
Generator Rated MVA
Generator FLA = ---------------------------------------------------------------------------------------------------------------------3 × Generator Rated Phase-Phase Voltage
(EQ 4.37)
Power quantities are programmed as per unit calculated from the rated MVA and rated power factor.
Demand is calculated in the following manner. Every minute, an average magnitude is calculated for current, +MW, +Mvar,
and MVA based on samples taken every 5 seconds. These values are stored in a FIFO (First In, First Out buffer).The size
of the buffer is dictated by the period that is selected for the setpoint. The average value of the buffer contents is calculated
and stored as the new demand value every minute. Demand for real and reactive power is only positive quantities (+MW
and +Mvar).
1
Demand = ---N
where:
N

Average N
(EQ 4.38)
n=1
N = programmed Demand Period in minutes,
n = time in minutes
4
160
MAGNITUDE
140
120
100
80
60
40
20
0
t=0
t+10
t+20
t+30
t+40
t+50
t+60
t+70
TIME
t+80
t+90
t+100
808717A1.CDR
Figure 4–21: ROLLING DEMAND (15 MINUTE WINDOW)
GE Multilin
489 Generator Management Relay
4-73
4.11 S10 MONITORING
4 SETPOINTS
4.11.6 PULSE OUTPUT
PATH: SETPOINTS  S10 MONITORING  PULSE OUTPUT
ð
 PULSE OUTPUT
 [ENTER] for more
ENTER
Range: Any combination of Relays 2 to 5
RELAYS (2-5): ----
ESCAPE
POS. kWh PULSE OUT
INTERVAL: 10 kWh
Range: 1 to 50000 kWh in steps of 1
POS. kvarh PULSE OUT
RELAYS (2-5): ----
Range: Any combination of Relays 2 to 5
POS. kvarh PULSE OUT
INTERVAL: 10 kvarh
Range: 1 to 50000 kvarh in steps of 1
NEG. kvarh PULSE OUT
RELAYS (2-5): ----
Range: Any combination of Relays 2 to 5
NEG. kvarh PULSE OUT
INTERVAL: 10 kvarh
Range: 1 to 50000 kvarh in steps of 1
PULSE WIDTH:
200 ms
Range: 200 to 1000 ms in steps of 1
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
4
ð POS. kWh PULSE OUT
ESCAPE
ESCAPE
MESSAGE
The 489 can perform pulsed output of positive kWh and both positive and negative kvarh. Each output parameter can be
assigned to any one of the alarm or auxiliary relays. Pulsed output is disabled for a parameter if the relay setpoint is
selected as OFF for that pulsed output. The minimum time between pulses is fixed to 400 milliseconds.
This feature should be programmed so that no more than one pulse per 600 milliseconds is required or the pulsing
will lag behind the interval activation. Do not assign pulsed outputs to the same relays as alarms and trip functions.
NOTE
normally open (NO) contact
→
status
↓
OPEN
status
↓
CLOSED
status
↓
OPEN
normally closed (NC) contact
→
CLOSED
OPEN
CLOSED
PULSE
WIDTH
808738A1.CDR
Figure 4–22: PULSE OUTPUT
4.11.7 GENERATOR RUNNING HOUR SETUP
PATH: SETPOINTS  S10 MONITORING  RUNNING HORU SETUP
ð
 RUNNING HOUR SETUP
 [ENTER] for more
ENTER
ð INITIAL GEN. RUNNING
Range: 0 to 999999 h in steps of 1
ESCAPE
HOURS: 0 h
ESCAPE
GEN. RUNNING HOURS
ALARM: Off
Range: Off, Latched, Unlatched
ASSIGN ALARM
RELAYS (2-5): ---5
Range: Any combination of Relays 2 to 5
GEN. RUNNING HOURS
LIMIT: 1000 h
Range: 1 to 1000000 h in steps of 1
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
The 489 can measure the generator running hours. This value may be of interest for periodic maintenance of the generator.
The initial generator running hour allows the user to program existing accumulated running hours on a particular generator
the relay is protecting. This feature switching 489 relays without losing previous generator running hour values.
4-74
489 Generator Management Relay
GE Multilin
4 SETPOINTS
4.12 S11 ANALOG I/O
4.12S11 ANALOG I/O
4.12.1 ANALOG OUTPUTS 1 TO 4
PATH: SETPOINTS  S11 ANALOG I/O  ANALOG OUTPUT 1(4)
ð
 ANALOG OUTPUT 1
 [ENTER] for more
ENTER
ESCAPE
REAL POWER (MW)
MIN: 0.00 x Rated
Range: 0.00 to 2.00 × Rated in steps of 0.01
REAL POWER (MW)
MAX: 1.25 x Rated
Range: 0.00 to 2.00 × Rated in steps of 0.01
ESCAPE
MESSAGE
ENTER
Range: See Table 4–8: Analog Output Parameter
Selection on page 4–76.
Apparent Power (MVA)
ESCAPE
APPARENT POWER (MVA)
MIN: 0.00 x Rated
Range: 0.00 to 2.00 × Rated in steps of 0.01
APPARENT POWER (MVA)
MAX: 1.25 x Rated
Range: 0.00 to 2.00 × Rated in steps of 0.01
ð
ESCAPE
MESSAGE
ENTER
ð ANALOG OUTPUT 3:
Avg. Output Current
ESCAPE
AVG. OUTPUT CURRENT
MIN: 0.00 x FLA
Range: 0.00 to 20.00 × Rated in steps of 0.01
AVG. OUTPUT CURRENT
MAX: 1.25 x FLA
Range: 0.00 to 20.00 × Rated in steps of 0.01
ð
ESCAPE
MESSAGE
ENTER
ð ANALOG OUTPUT 4:
Range: See Table 4–8: Analog Output Parameter
Selection on page 4–76.
ESCAPE
Average Voltage
ESCAPE
AVERAGE VOLTAGE
MIN: 0.00 x Rated
Range: 0.00 to 1.50 × Rated in steps of 0.01
AVERAGE VOLTAGE
MAX: 1.25 x Rated
Range: 0.00 to 1.50 × Rated in steps of 0.01
ð
MESSAGE
ESCAPE
MESSAGE
4
Range: See Table 4–8: Analog Output Parameter
Selection on page 4–76.
ESCAPE
MESSAGE
 ANALOG OUTPUT 4
 [ENTER] for more
ð ANALOG OUTPUT 2:
ESCAPE
MESSAGE
 ANALOG OUTPUT 3
 [ENTER] for more
Range: See Table 4–8: Analog Output Parameter
Selection on page 4–76.
Real Power (MW)
MESSAGE
 ANALOG OUTPUT 2
 [ENTER] for more
ð ANALOG OUTPUT 1:
ESCAPE
The 489 has four analog output channels (4 to 20 mA or 0 to 1 mA as ordered). Each channel may be individually configured to represent a number of different measured parameters as shown in the table below. The minimum value programmed represents the 4 mA output. The maximum value programmed represents the 20 mA output. All four of the
outputs are updated once every 50 ms. Each parameter may only be used once.
The analog output parameter may be chosen as Real Power (MW) for a 4 to 20 mA output. If rated power is 100 MW, the
minimum is set for 0.00 × Rated, and the maximum is set for 1.00 × Rated, the analog output channel will output 4 mA
when the real power measurement is 0 MW. When the real power measurement is 50 MW, the analog output channel will
output 12 mA. When the real power measurement is 100 MW, the analog output channel will output 20 mA.
GE Multilin
489 Generator Management Relay
4-75
4.12 S11 ANALOG I/O
4 SETPOINTS
Table 4–8: ANALOG OUTPUT PARAMETER SELECTION
PARAMETER NAME
RANGE / UNITS
DEFAULT
MIN.
MAX
IA Output Current
0.00 to 20.00 × FLA
0.01
0.00
1.25
IB Output Current
0.00 to 20.00 × FLA
0.01
0.00
1.25
IC Output Current
0.00 to 20.00 × FLA
0.01
0.00
1.25
Avg. Output Current
0.00 to 20.00 × FLA
0.01
0.00
1.25
Neg. Seq. Current
Averaged Gen. Load
0 to 2000% FLA
1
0
100
0.00 to 20.00 × FLA
0.01
0.00
1.25
Hottest Stator RTD
–50 to +250°C or –58 to +482°F
1
0
200
Hottest Bearing RTD
–50 to +250°C or –58 to +482°F
1
0
200
Ambient RTD
–50 to +250°C or –58 to +482°F
1
–50
60
RTDs 1 to 12
–50 to +250°C or –58 to +482°F
1
–50
250
AB Voltage
0.00 to 1.50 × Rated
0.01
0.00
1.25
BC Voltage
0.00 to 1.50 × Rated
0.01
0.00
1.25
1.25
CA Voltage
0.00 to 1.50 × Rated
0.01
0.00
Volts/Hertz
0.00 to 2.00 × Rated
0.01
0.00
1.50
Frequency
0.00 to 90.00 Hz
0.01
59.00
61.00
0 to 25000 V
0.1
0.0
45.0
Neutral Volt. (3rd)
Average Voltage
0.00 to 1.50 × Rated
0.01
0.00
1.25
Power Factor
0.01 to 1.00 lead/lag
0.01
0.8 lag
0.8 lead
Reactive Power (Mvar)
–2.00 to 2.00 × Rated
0.01
0.00
1.25
Real Power
–2.00 to 2.00 × Rated
0.01
0.00
1.25
Apparent Power
0.00 to 2.00 × Rated
0.01
0.00
1.25
–50000 to +50000
1
0
50000
0 to 7200 RPM
1
3500
3700
0 to 100%
1
0
100
Current Demand
0.00 to 20.00 × FLA
0.01
0.00
1.25
Mvar Demand
0.00 to 2.00 × Rated
0.01
0.00
1.25
MW Demand
0.00 to 2.00 × Rated
0.01
0.00
1.25
MVA Demand
0.00 to 2.00 × Rated
0.01
0.00
1.25
Analog Inputs 1 to 4
Tachometer
Thermal Capacity Used
4.12.2 ANALOG INPUTS 1 TO 4
PATH: SETPOINTS  S11 ANALOG I/O  ANALOG INPUT 1(4)
 ANALOG INPUT 1
 [ENTER] for more
ð
4
STEP
ENTER
Range: Disabled, 4-20 mA, 0-20 mA, 0-1 mA
Disabled
ESCAPE
ANALOG INPUT1 NAME:
Analog I/P 1
Range: 12 alphanumeric characters
ANALOG INPUT1 UNITS:
Units
Range: 6 alphanumeric characters
ANALOG INPUT1
MINIMUM: 0
Range: –50000 to 50000 in steps of 1
ANALOG INPUT1
MAXIMUM: 100
Range: –50000 to 50000 in steps of 1
BLOCK ANALOG INPUT1
FROM ONLINE: 0 s
Range: 0 to 5000 sec. in steps of 1
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
4-76
ð ANALOG INPUT1:
ESCAPE
489 Generator Management Relay
GE Multilin
4 SETPOINTS
4.12 S11 ANALOG I/O
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ANALOG INPUT1
ALARM: Off
Range: Off, Latched, Unlatched
ASSIGN ALARM
RELAYS (2-5): ---5
Range: Any combination of Relays 2 to 5
ANALOG INPUT1 ALARM
LEVEL: 10 Units
Range: –50000 to 50000 in steps of 1
Units reflect ANALOG INPUT 1 UNITS above
ANALOG INPUT1 ALARM
PICKUP: Over
Range: Over, Under
ANALOG INPUT1 ALARM
DELAY: 0.1 s
Range: 0.1 to 300.0 s in steps of 0.1
ANALOG INPUT1 ALARM
EVENTS: Off
Range: On, Off
ANALOG INPUT1
TRIP: Off
Range: Off, Latched, Unlatched
ASSIGN TRIP
RELAYS (1-4): 1---
Range: Any combination of Relays 1 to 4
ANALOG INPUT1 TRIP
LEVEL: 20 Units
Range: –50000 to 50000 in steps of 1
Units reflect ANALOG INPUT 1 UNITS above
ANALOG INPUT1 TRIP
PICKUP: Over
Range: Over, Under
ANALOG INPUT1 TRIP
DELAY: 0.1 s
Range: 0.1 to 300.0 s in steps of 0.1
4
There are 4 analog inputs (4 to 20 mA, 0 to 20 mA, or 0 to 1 mA) that may be used to monitor transducers such as vibration
monitors, tachometers, pressure transducers, etc. These inputs may be used for alarm and/or tripping purposes. The inputs
are sampled every 50 ms. The level of the analog input is also available over the communications port. With the 489PC
program, the level of the transducer may be trended and graphed.
Before the input may be used, it must be configured. A name may be assigned for the input, units may be assigned, and a
minimum and maxi-mum value must be assigned. Also, the trip and alarm features may be blocked until the generator is
online for a specified time delay. If the block time is 0 seconds, there is no block and the trip and alarm features will be
active when the generator is offline or online. If a time is programmed other than 0 seconds, the feature will be disabled
when the generator is offline and also from the time the machine is placed online until the time entered expires. Once the
input is setup, both the trip and alarm features may be configured. In addition to programming a level and time delay, the
PICKUP setpoint may be used to dictate whether the feature picks up when the measured value is over or under the level.
If a vibration transducer is to be used, program the name as "Vibration Monitor", the units as "mm/s", the minimum as "0",
the maximum as "25", and the Block From Online as "0 s". Set the alarm for a reasonable level slightly higher than the normal vibration level. Program a delay of "3 s" and the pickup as "Over".
GE Multilin
489 Generator Management Relay
4-77
4.13 S12 TESTING
4 SETPOINTS
4.13S12 TESTING
4.13.1 SIMULATION MODE
PATH: SETPOINTS  S12 TESTING  SIMULATION MODE
ð
 SIMULATION MODE
 [ENTER] for more
ENTER
ESCAPE
ESCAPE
MESSAGE
ð SIMULATION MODE:
Off
PRE-FAULT TO FAULT
TIME DELAY:
15 s
Range: Off, Simulate Pre-Fault, Simulate Fault, Pre-Fault
to Fault
Range: 0 to 300 s in steps of 1
The 489 may be placed in several simulation modes. This simulation may be useful for several purposes. First, it may be
used to under-stand the operation of the 489 for learning or training purposes. Second, simulation may be used during
startup to verify that control circuitry operates as it should in the event of a trip or alarm. In addition, simulation may be used
to verify that setpoints had been set properly in the event of fault conditions.
4
The SIMULATION MODE setpoint may be entered only if the generator is offline, no current is measured, and there are no
trips or alarms active. The values entered as Pre-Fault Values will be substituted for the measured values in the 489 when
the SIMULATION MODE is "Simulate Pre-Fault". The values entered as Fault Values will be substituted for the measured values in the 489 when the SIMULATION MODE is "Simulate Fault". If the SIMULATION MODE is set to "Pre-Fault to Fault", the
Pre-Fault values will be substituted for the period of time specified by the delay, followed by the Fault values. If a trip
occurs, the SIMULATION MODE reverts to "Off". Selecting "Off" for the SIMULATION MODE places the 489 back in service. If the
489 measures current or control power is cycled, the SIMULATION MODE automatically reverts to "Off".
If the 489 is to be used for training, it might be desirable to allow all parameter averages, statistical information, and event
recording to update when operating in simulation mode. If however, the 489 has been installed and will remain installed on
a specific generator, it might be desirable assign a digital input to Test Input and to short that input to prevent all of this data
from being corrupted or updated. In any event, when in simulation mode, the 489 In Service LED (indicator) will flash, indicating that the 489 is not in protection mode.
4-78
489 Generator Management Relay
GE Multilin
4 SETPOINTS
4.13 S12 TESTING
4.13.2 PRE-FAULT SETUP
PATH: SETPOINTS  S12 TESTING  PRE-FAULT SETUP
ð
 PRE-FAULT SETUP
 [ENTER] for more
ENTER
ð PRE-FAULT Iphase
Range: 0.00 to 20.00 × CT in steps of 0.01
ESCAPE
OUTPUT: 0.00 x CT
ESCAPE
PRE-FAULT VOLTAGES
PHASE-N: 1.00 x Rated
Range: 0.00 to 1.50 × Rated in steps of 0.01
Entered as a phase-to-neutral quantity.
PRE-FAULT CURRENT
LAGS VOLTAGE: 0°
Range: 0 to 359° in steps of 1
PRE-FAULT Iphase
NEUTRAL: 0.00 x CT
Range: 0.00 to 20.00 × CT in steps of 0.01
180° phase shift with respect to Iphase OUTPUT
PRE-FAULT CURRENT
GROUND: 0.00 x CT
Range: 0.00 to 20.00 × CT in steps of 0.01
CT is either XXX:1 or 50:0.025
PRE-FAULT VOLTAGE
NEUTRAL: 0 Vsec
Range
PRE-FAULT STATOR
RTD TEMP: 40°C
Range: –50 to 250°C in steps of 1
PRE-FAULT BEARING
RTD TEMP: 40°C
Range: –50 to 250°C in steps of 1
PRE-FAULT OTHER
RTD TEMP: 40°C
Range: –50 to 250°C in steps of 1
PRE-FAULT AMBIENT
RTD TEMP: 40°C
Range: –50 to 250°C in steps of 1
PRE-FAULT SYSTEM
FREQUENCY: 60.0 Hz
Range: 5.0 to 90.0 Hz in steps of 0.1
PRE-FAULT ANALOG
INPUT 1: 0%
Range: 0 to 100% in steps of 1
PRE-FAULT ANALOG
INPUT 2: 0%
Range: 0 to 100% in steps of 1
PRE-FAULT ANALOG
INPUT 3: 0%
Range: 0 to 100% in steps of 1
PRE-FAULT ANALOG
INPUT 4: 0%
Range: 0 to 100% in steps of 1
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
0.0 to 100.0 Vsec in steps of 0.1
Fundamental value only in secondary units
4
The values entered under Pre-Fault Values will be substituted for the measured values in the 489 when the SIMULATION
is "Simulate Pre-Fault".
MODE
GE Multilin
489 Generator Management Relay
4-79
4.13 S12 TESTING
4 SETPOINTS
4.13.3 FAULT SETUP
PATH: SETPOINTS  S12 TESTING  FAULT SETUP
ð
 FAULT SETUP
 [ENTER] for more
ENTER
OUTPUT: 0.00 x CT
ESCAPE
FAULT VOLTAGES
PHASE-N: 1.00 x Rated
Range: 0.00 to 1.50 × Rated in steps of 0.01
Entered as a phase-to-neutral quantity.
FAULT CURRENT
LAGS VOLTAGE:
Range: 0 to 359° in steps of 1
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
4
Range: 0.00 to 20.00 × CT in steps of 0.01
ð FAULT Iphase
ESCAPE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
0°
FAULT Iphase
NEUTRAL: 0.00 x CT
Range: 0.00 to 20.00 × CT in steps of 0.01
180° phase shift with respect to Iphase OUTPUT
FAULT CURRENT
GROUND: 0.00 x CT
Range: 0.00 to 20.00 × CT in steps of 0.01
CT is either XXX:1 or 50:0.025
FAULT VOLTAGE
NEUTRAL: 0 Vsec
Range: 0.0 to 100.0 Vsec in steps of 0.1
Fundamental value only in secondary volts
FAULT STATOR
RTD TEMP: 40°C
Range: –50 to 250°C in steps of 1
FAULT BEARING
RTD TEMP: 40°C
Range: –50 to 250°C in steps of 1
FAULT OTHER
RTD TEMP: 40°C
Range: –50 to 250°C in steps of 1
FAULT AMBIENT
RTD TEMP: 40°C
Range: –50 to 250°C in steps of 1
FAULT SYSTEM
FREQUENCY: 60.0 Hz
Range: 5.0 to 90.0 Hz in steps of 0.1
FAULT ANALOG
INPUT 1: 0%
Range: 0 to 100% in steps of 1
FAULT ANALOG
INPUT 2: 0%
Range: 0 to 100% in steps of 1
FAULT ANALOG
INPUT 3: 0%
Range: 0 to 100% in steps of 1
FAULT ANALOG
INPUT 4: 0%
Range: 0 to 100% in steps of 1
The values entered here are substituted for the measured values in the 489 when the SIMULATION MODE is "Simulate Fault".
4-80
489 Generator Management Relay
GE Multilin
4 SETPOINTS
4.13 S12 TESTING
4.13.4 TEST OUTPUT RELAYS
PATH: SETPOINTS  S12 TESTING  TEST OUTPUT RELAYS
ð
 TEST OUTPUT RELAYS
 [ENTER] for more
ENTER
ESCAPE
ð FORCE OPERATION OF
RELAYS: Disabled
Range: Disabled, R1 Trip, R2 Auxiliary, R3 Auxiliary, R4
Auxiliary, R5 Alarm, R6 Service, All Relays, No
Relays
The test output relays setpoint may be used during startup or testing to verify that the output relays are functioning correctly. The output relays can be forced to operate only if the generator is offline, no current is measured, and there are no
trips or alarms active. If any relay is forced to operate, the relay will toggle from its normal state when there are no trips or
alarms to its operated state. The appropriate relay indicator will illuminate at that time. Selecting "Disabled" places the output relays back in service. If the 489 measures current or control power is cycled, the force operation of relays setpoint will
automatically become disabled and the output relays will revert back to their normal states.
If any relay is forced, the 489 In Service indicator will flash, indicating that the 489 is not in protection mode.
4.13.5 TEST ANALOG OUTPUT
PATH: SETPOINTS  S12 TESTING  TEST ANALOG OUTPUT
ð
 TEST ANALOG OUTPUT
 [ENTER] for more
ENTER
ð FORCE ANALOG OUTPUTS
FUNCTION: Disabled
ESCAPE
ANALOG OUTPUT 1
FORCED VALUE: 0%
Range: 0 to 100% in steps of 1
ANALOG OUTPUT 2
FORCED VALUE: 0%
Range: 0 to 100% in steps of 1
ANALOG OUTPUT 3
FORCED VALUE: 0%
Range: 0 to 100% in steps of 1
ANALOG OUTPUT 4
FORCED VALUE: 0%
Range: 0 to 100% in steps of 1
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
4
Range: Enabled, Disabled
ESCAPE
These setpoints may be used during startup or testing to verify that the analog outputs are functioning correctly. The analog
outputs can be forced only if the generator is offline, no current is measured, and there are no trips or alarms active. When
the FORCE ANALOG OUTPUTS FUNCTION is "Enabled", the output reflects the forced value as a percentage of the range
4 to 20 mA or 0 to 1 mA. Selecting "Disabled" places all four analog output channels back in service, reflecting their programmed parameters. If the 489 measures current or control power is cycled, the force analog output function is automatically disabled and all analog outputs will revert back to their normal state.
Any time the analog outputs are forced, the In Service indicator will flash, indicating that the 489 is not in protection mode.
GE Multilin
489 Generator Management Relay
4-81
4.13 S12 TESTING
4 SETPOINTS
4.13.6 COMM PORT MONITOR
PATH: SETPOINTS  S12 TESTING  COMM PORT MONITOR
ð
 COMM PORT MONITOR
 [ENTER] for more
ENTER
ð MONITOR COMM. PORT:
Range: Computer RS485, Auxiliary RS485,
Front Panel RS232
ESCAPE
Computer RS485
ESCAPE
CLEAR COMM.
BUFFERS: No
Range: No, Yes
LAST Rx BUFFER:
Received OK
Range: Buffer Cleared, Received OK, Wrong Slave
Addr., Illegal Function, Illegal Count, Illegal Reg.
Addr., CRC Error, Illegal Data
Rx1: 02,03,00,67,00,
03,B4,27
Range: received data in HEX
MESSAGE
ESCAPE
Rx2:
Range: received data in HEX
Tx1: 02,03,06,00,64,
00,0A,00,0F
Range: received data in HEX
MESSAGE
ESCAPE
Tx2:
Range: received data in HEX
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
4
MESSAGE
During communications troubleshooting, it can be useful to see the data being transmitted to the 489 from some master
device, as well as the data transmitted back to that master device. The messages shown here make it possible to view that
data. Any of the three communications ports may be monitored. After the communications buffers are cleared, any data
received from the monitored communications port is stored in Rx1 and Rx2. If the 489 transmits a message, it appears in
the Tx1 and Tx2 buffers. In addition to these buffers, there is a message indicating the status of the last received message.
4.13.7 FACTORY SERVICE
PATH: SETPOINTS  S12 TESTING  FACTORY SERVICE
ð
 FACTORY SERVICE
 [ENTER] for more
ENTER
ESCAPE
ð ENTER FACTORY
Range: N/A
PASSCODE: 0
This section is for use by GE Multilin personnel for testing and calibration purposes.
4-82
489 Generator Management Relay
GE Multilin
5 ACTUAL VALUES
5.1 OVERVIEW
5 ACTUAL VALUES 5.1OVERVIEW
5.1.1 ACTUAL VALUES MESSAGES
Measured values, maintenance and fault analysis information are accessed in the Actual Value mode. Actual values may
be accessed via one of the following methods:
1.
Front panel, using the keys and display.
2.
Front program port, and a portable computer running the 489PC software supplied with the relay.
3.
Rear terminal RS485 port, and a PLC/SCADA system running user-written software.
Any of these methods can be used to view the same information. However, a computer makes viewing much more convenient since many variables may be viewed simultaneously.
Actual value messages are organized into logical groups, or pages, for easy reference, as shown below. All actual value
messages are illustrated and described in blocks throughout this chapter. All values shown in these message illustrations
assume that no inputs (besides control power) are connected to the 489.
ð
 A1 ACTUAL VALUES
 STATUS
ENTER
ð
ESCAPE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
 GENERATOR STATUS
 [ENTER] for more
See page 5–3.
 LAST TRIP DATA
 [ENTER] for more
See page 5–3.
 ALARM STATUS
 [ENTER] for more
See page 5–4.
 TRIP PICKUPS
 [ENTER] for more
See page 5–6.
 ALARM PICKUPS
 [ENTER] for more
See page 5–9.
 DIGITAL INPUTS
 [ENTER] for more
See page 5–12.
 REAL TIME CLOCK
 [ENTER] for more
See page 5–12.
 CURRENT METERING
 [ENTER] for more
See page 5–13.
 VOLTAGE METERING
 [ENTER] for more
See page 5–14.
 POWER METERING
 [ENTER] for more
See page 5–15.
 TEMPERATURE
 [ENTER] for more
See page 5–16.
 DEMAND METERING
 [ENTER] for more
See page 5–17.
 ANALOG INPUTS
 [ENTER] for more
See page 5–17.
 SPEED
 [ENTER] for more
See page 5–17.
5
ESCAPE
MESSAGE
ð
 A2 ACTUAL VALUES
 METERING DATA
ENTER
ESCAPE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ð
ESCAPE
MESSAGE
GE Multilin
489 Generator Management Relay
5-1
5.1 OVERVIEW
ð
 A3 ACTUAL VALUES
 LEARNED DATA
5 ACTUAL VALUES
ENTER
ð
ESCAPE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
 PARAMETER AVERAGES
 [ENTER] for more
See page 5–18.
 RTD MAXIMUMS
 [ENTER] for more
See page 5–18.
 ANALOG IN MIN/MAX
 [ENTER] for more
See page 5–19.
 TRIP COUNTERS
 [ENTER] for more
See page 5–20.
 GENERAL COUNTERS
 [ENTER] for more
See page 5–22.
 TIMERS
 [ENTER] for more
See page 5–22.
 [ENTER] EVENT 01
 [ENTER] for more
See page 5–23.
ESCAPE
MESSAGE
ð
 A4 ACTUAL VALUES
 MAINTENANCE
ENTER
ð
ESCAPE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ð
 A5 ACTUAL VALUES
 EVENT RECORD
ENTER
ð
ESCAPE
 [ENTER] EVENT 02
 [ENTER] for more
ESCAPE
MESSAGE
5
↓
 [ENTER] EVENT 40
 [ENTER] for more
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ð
 A6 ACTUAL VALUES
 PRODUCT INFO.
ENTER
ESCAPE
ESCAPE
MESSAGE
ð
 489 MODEL INFO.
 [ENTER] for more
See page 5–25.
 CALIBRATION INFO.
 [ENTER] for more
See page 5–25.
In addition to the actual value messages, there are also diagnostic and flash messages that appear only when certain conditions occur. They are described later in this chapter.
5-2
489 Generator Management Relay
GE Multilin
5 ACTUAL VALUES
5.2 A1 STATUS
5.2A1 STATUS
5.2.1 GENERATOR STATUS
PATH: ACTUAL VALUES  A1 STATUS  GENERATOR STATUS
ð
 GENERATOR STATUS
 [ENTER] for more
ENTER
ð GENERATOR STATUS:
Range: Online, Offline, Tripped
ESCAPE
Offline
ESCAPE
GENERATOR THERMAL
CAPACITY USED: 0%
Range: 0 to 100%
Seen only if the Thermal Model is enabled
ESTIMATED TRIP TIME
ON OVERLOAD: Never
Range: 0 to 10000 sec., Never
Seen only if the Thermal Model is enabled
MESSAGE
ESCAPE
MESSAGE
These messages describe the status of the generator at any given point in time. If the generator has been tripped, is still
offline, and the 489 has not yet been reset, the GENERATOR STATUS will be "Tripped". The GENERATOR THERMAL CAPACITY
USED value reflects an integrated value of both the stator and rotor thermal capacity used. The values for ESTIMATED TRIP
TIME ON OVERLOAD will appear whenever the 489 thermal model picks up on the overload curve.
5.2.2 LAST TRIP DATA
PATH: ACTUAL VALUES  A1 STATUS  LAST TRIP DATA
ð
 LAST TRIP DATA
 [ENTER] for more
ENTER
ESCAPE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
GE Multilin
ð CAUSE OF LAST TRIP:
No Trip to Date
Range: No Trip to Date, General Input A to G, Sequential
Trip, Field-Bkr Discrep., Tachometer, Thermal
Model, Offline Overcurrent, Phase Overcurrent,
Neg. Seq. Overcurrent, Ground Overcurrent,
Phase Differential, RTDs 1 to 12, Overvoltage,
Undervoltage, Volts/Hertz, Phase Reversal,
Underfrequency, Overfrequency, Neutral O/V,
Neutral U/V (3rd), Reactive Power, Reverse
Power, Low Forward Power, Inadvertent Energ.,
Analog Inputs 1 to 4
TIME OF LAST TRIP:
09:00:00.00
Range: hour:min:sec
DATE OF LAST TRIP:
Jan 01 1995
Range: Month Day Year
TACHOMETER
PRETRIP: 3600 RPM
Range: 0 to 3600 RPM
Seen only if Tachometer is assigned as an input.
A:
C:
0
0
B:
0
A PreTrip
Range: 0 to 999999 A. Represents current measured
from output CTs. Seen only if a trip has occurred.
a:
c:
0
0
b:
0
DA PreTrip
Range: 0 to 999999 A. Represents differential current.
Seen only if differential element is enabled.
NEG. SEQ. CURRENT
PRETRIP: 0% FLA
Range: 0 to 2000% FLA
Seen only if there has been a trip.
GROUND CURRENT
PRETRIP: 0.00 A
Range: 0.00 to 200000.00 A
Not seen if GROUND CT is "None"
GROUND CURRENT
PRETRIP: 0.00 Amps
Range: 0.0 to 5000.0 A
Vab:
Vca:
Range: 0 to 50000 V
Not seen if VT CONNECTION is "None"
0
0
Vbc:
0
V PreTrip
FREQUENCY
PRETRIP: 0.00 Hz
Range: 0.00 to 90.00 Hz
Not seen if VT CONNECTION is "None"
NEUTRAL VOLT (FUND)
PRETRIP: 0.0 V
Range: 0.0 to 25000.0 V
Seen only if there
transformer.
489 Generator Management Relay
is
a
neutral
voltage
5-3
5
5.2 A1 STATUS
5 ACTUAL VALUES
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
5
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
NEUTRAL VOLT (3rd)
PRETRIP: 0.0 V
Range: 0.0 to 25000.0 V
Seen only if there
transformer.
REAL POWER (MW)
PRETRIP: 0.000
Range: 0.000 to ±2000.000 MW
Not seen if VT CONNECTION is "None"
REACTIVE POWER Mvar
PRETRIP: 0.00 Hz
Range: 0.000 to ±2000.000 Mvar
Not seen if VT CONNECTION is "None"
APPARENT POWER MVA
PRETRIP: 0.00 Hz
Range: 0.000 to ±2000.000 MVA
Not seen if VT CONNECTION is "None"
HOTTEST STATOR RTD
RTD #1: 0°C PreTrip
Range: –50 to 250°C
Seen only if at least one RTD is "Stator"
HOTTEST BEARING RTD
RTD #7: 0°C PreTrip
Range: –50 to 250°C
Seen only if at least one RTD is "Bearing"
HOTTEST OTHER RTD
RTD #11: 0°C PreTrip
Range: –50 to 250°C
Seen only if at least one RTD is "Other"
AMBIENT RTD
RTD#12: 0°C PreTrip
Range: –50 to 250°C
Seen only if at least one RTD is Ambient
ANALOG INPUT 1
PreTrip: 0 Units
Range: –50000 to 50000
Not seen if VT CONNECTION is "None"
ANALOG INPUT 2
PreTrip: 0 Units
Range: –50000 to 50000
Not seen if VT CONNECTION is "None"
ANALOG INPUT 3
PreTrip: 0 Units
Range: –50000 to 50000
Not seen if VT CONNECTION is "None"
ANALOG INPUT 4
PreTrip: 0 Units
Range: –50000 to 50000
Not seen if VT CONNECTION is "None"
Vab/Iab PreTrip:
0.0 Ωsec.
0°
Range: 0 to 65535 Ωsec; 0 to 359°
Seen only if Loss of Excitation is enabled
is
a
neutral
voltage
Immediately prior to issuing a trip, the 489 takes a snapshot of generator parameters and stores them as pre-trip values;
this allows for troubleshooting after the trip occurs. The cause of last trip message is updated with the current trip and the
screen defaults to that message. All trip features are automatically logged as date and time stamped events as they occur.
This information can be cleared using the S1 489 SETUP  CLEAR DATA  CLEAR LAST TRIP DATA setpoint. If the cause of
last trip is "No Trip To Date", the subsequent pretrip messages will not appear. Last Trip Data will not update if a digital input
programmed as Test Input is shorted.
5.2.3 ALARM STATUS
PATH: ACTUAL VALUES  A1 STATUS  ALARM STATUS
ð
 ALARM STATUS
 [ENTER] for more
ENTER
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
5-4
ð NO ALARMS
ESCAPE
Range: N/A
Message seen when no alarms are active
Input A ALARM
STATUS: Active
Range: Active, Latched. The first line of this alarm
message reflects the Input Name as
programmed. Status is Active if the condition
that caused the alarm is still present
Input B ALARM
STATUS: Active
Range: see Input A ALARM STATUS
Input C ALARM
STATUS: Active
Range: see Input A ALARM STATUS
489 Generator Management Relay
GE Multilin
5 ACTUAL VALUES
5.2 A1 STATUS
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
GE Multilin
Input D ALARM
STATUS: Active
Range: see Input A ALARM STATUS
Input E ALARM
STATUS: Active
Range: see Input A ALARM STATUS
Input F ALARM
STATUS: Active
Range: see Input A ALARM STATUS
Input G ALARM
STATUS: Active
Range: see Input A ALARM STATUS
TACHOMETER
ALARM: 3000 RPM
Range: 0 to 3600 RPM. The current Tachometer
Digital Input value is shown here
OVERCURRENT
ALARM: 10.00 x FLA
Range: 0.00 to 20.00 × FLA
The overcurrent level is shown here.
NEG. SEQ. CURRENT
ALARM: 15% FLA
Range: 0 to 100% FLA. Reflects the present negativesequence current level.
GROUND OVERCURRENT
ALARM: 5.00 A
Range: 0.00 to 200000.00 A. Seen only if the GE HGF
CT is used. Reflects the present ground
current level.
GROUND DIRECTIONAL
ALARM: 5.00 A
Range: 0.00 to 200000.00 A
UNDERVOLTAGE ALARM
Vab= 3245 V 78% Rated
Range: 0 to 20000 V; 50 to 99% of Rated. The lowest
phase-to-phase voltage value is shown here
OVERVOLTAGE ALARM
Vab= 4992 V 120% Rated
Range: 0 to 20000 V; 101 to 150% of Rated. The
lowest phase-to-phase voltage is shown here
VOLTS/HERTZ ALARM
PER UNIT V/Hz: 1.15
Range: 0.00 to 2.00. The present V/Hz value is shown
here. Not seen if VT CONNECTION is None.
UNDERFREQUENCY
ALARM: 59.4 Hz
Range: 0.00 to 90.00 Hz
Reflects the present voltage frequency value.
OVERFREQUENCY
ALARM: 60.6 Hz
Range: 0.00 to 90.00 Hz
Reflects the present voltage frequency value.
NEUTRAL O/V (FUND)
ALARM: 0.0 V
Range: 0.0 to 25000.0 V. The present fundamental
neutral voltage value is displayed here.
NEUTRAL U/V (3rd)
ALARM: 0.0 V
Range: 0.0 to 25000.0 V. The present 3rd harmonic
neutral voltage value is displayed here.
REACTIVE POWER Mvar
ALARM: +20.000
Range: –2000.000 to +2000.000 Mvar
The current Mvar value is shown here
REVERSE POWER
ALARM: –20.000 MW
Range: –2000.000 to +2000.000 MW
The current MW value is shown here
LOW FORWARD POWER
ALARM: –20.000 MW
Range: –2000.000 to +2000.000 MW
The current MW value is shown here
STATOR RTD #1
ALARM: 135°C
Range: –50 to +250°C. The present RTD temperature
is shown. Reflects programmed RTD Name.
OPEN SENSOR ALARM:
RTD # 1 2 3 4 5 6 ...
Range: RTDs 1 to 12. Reflects the RTD(s) that caused
the open sensor alarm.
SHORT/LOW TEMP ALARM
RTD # 7 8 9 10 11 ...
Range: RTDs 1 to 12. Reflects the RTD(s) that caused
the short/low temp. alarm.
489 Generator Management Relay
5-5
5
5.2 A1 STATUS
5 ACTUAL VALUES
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
5
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
THERMAL MODEL
ALARM: 100% TC USED
Range: 1 to 100%
The thermal capacity used is shown here.
TRIP COUNTER
ALARM: 25 Trips
Range: 1 to 10000
The number of generator trips is shown here.
BREAKER FAILURE
ALARM: Active
Range: Active, Latched. Active if condition that caused
the alarm is still present.
TRIP COIL MONITOR
ALARM: Active
Range: Active, Latched. Active if condition that caused
the alarm is still present.
VT FUSE FAILURE
ALARM: Active
Range: Active, Latched. Active if condition that caused
the alarm is still present.
CURRENT DEMAND
ALARM: 1053 A
Range: 1 to 999999 A.
The running current demand is shown here.
MW DEMAND
ALARM: 50.500
Range: –2000.000 to +2000.000 MW
Current Running MW Demand is shown here
Mvar DEMAND
ALARM: –20.000
Range: –2000.000 to +2000.000 Mvar
Current Running Mvar Demand is shown here
MVA DEMAND
ALARM: 20.000
Range: 0 to 2000.000 MVA
Current Running MVA Demand is shown here
GEN. RUNNING HOURS
ALARM: 1000 h
Range: 0 to 1000000 hrs. Seen only if the Running
Hour Alarm is enabled.
ANALOG I/P 1
ALARM: 201 Units
Range: –50000 to +50000. Reflects the Analog Input 1
Name. The Analog Input level is shown here.
ANALOG I/P 2
ALARM: 201 Units
Range: –50000 to +50000. Reflects the Analog Input 2
Name. The Analog Input level is shown here.
ANALOG I/P 3
ALARM: 201 Units
Range: –50000 to +50000. Reflects the Analog Input 3
Name. The Analog Input level is shown here.
ANALOG I/P 4
ALARM: 201 Units
Range: –50000 to +50000. Reflects the Analog Input 4
Name. The Analog Input level is shown here.
ALARM, 489 NOT
INSERTED PROPERLY
If the 489 chassis is only partially engaged with the
case, this service alarm appears after 1 sec.
Secure the chassis handle to ensure that all
contacts mate properly
489 NOT IN SERVICE
Simulation Mode
Range: Not Programmed, Simulation Mode, Output
Relays Forced, Analog Output Forced, Test
Switch Shorted
IRIG-B FAILURE
ALARM: Active
Range: Active. Seen only if IRIG-B is enabled and the
associated signal input is lost.
Any active or latched alarms may be viewed here.
5.2.4 TRIP PICKUPS
PATH: ACTUAL VALUES  A1 STATUS  TRIP PICKUPS
ð
 TRIP PICKUPS
 [ENTER] for more
ENTER
PICKUP: Not Enabled
ESCAPE
Input B
PICKUP: Not Enabled
MESSAGE
5-6
ð Input A
ESCAPE
Range: Not Enabled, Inactive, Timing Out, Active Trip,
Latched Trip. Reflects Input Name as
programmed. Seen only if function assigned is
an input.
Range: see Input A PICKUP above
489 Generator Management Relay
GE Multilin
5 ACTUAL VALUES
5.2 A1 STATUS
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
GE Multilin
Input C
PICKUP: Not Enabled
Range: see Input A PICKUP above
Input D
PICKUP: Not Enabled
Range: see Input A PICKUP above
Input E
PICKUP: Not Enabled
Range: see Input A PICKUP above
Input F
PICKUP: Not Enabled
Range: see Input A PICKUP above
Input G
PICKUP: Not Enabled
Range: see Input A PICKUP above
SEQUENTIAL TRIP
PICKUP: Not Enabled
Range: Not Enabled, Inactive, Timing Out, Active Trip,
Latched Trip. Seen only if function is an input.
FIELD-BKR DISCREP.
PICKUP: Not Enabled
Range: Not Enabled, Inactive, Timing Out, Active Trip,
Latched Trip. Seen only if function is an input.
TACHOMETER
PICKUP: Not Enabled
Range: Not Enabled, Inactive, Timing Out, Active Trip,
Latched Trip. Seen only if function is an input.
OFFLINE OVERCURRENT
PICKUP: Not Enabled
Range: Not Enabled, Inactive, Timing Out, Active Trip,
Latched Trip.
INADVERTENT ENERG.
PICKUP: Not Enabled
Range: Not Enabled, Inactive, Timing Out, Active Trip,
Latched Trip.
PHASE OVERCURRENT
PICKUP: Not Enabled
Range: Not Enabled, Inactive, Timing Out, Active Trip,
Latched Trip.
NEG. SEQ. OVERCURRENT
PICKUP: Not Enabled
Range: Not Enabled, Inactive, Timing Out, Active Trip,
Latched Trip.
GROUND OVERCURRENT
PICKUP: Not Enabled
Range: Not Enabled, Inactive, Timing Out, Active Trip,
Latched Trip.
PHASE DIFFERENTIAL
PICKUP: Not Enabled
Range: Not Enabled, Inactive, Timing Out, Active Trip,
Latched Trip.
GROUND DIRECTIONAL
PICKUP: Not Enabled
Range: Not Enabled, Inactive, Timing Out, Active Trip,
Latched Trip.
HIGH-SET PHASE O/C
PICKUP: Not Enabled
Range: Not Enabled, Inactive, Timing Out, Active Trip,
Latched Trip.
UNDERVOLTAGE
PICKUP: Not Enabled
Range: Not Enabled, Inactive, Timing Out, Active Trip,
Latched Trip.
OVERVOLTAGE
PICKUP: Not Enabled
Range: Not Enabled, Inactive, Timing Out, Active Trip,
Latched Trip.
VOLTS/HERTZ
PICKUP: Not Enabled
Range: Not Enabled, Inactive, Timing Out, Active Trip,
Latched Trip.
PHASE REVERSAL
PICKUP: Not Enabled
Range: Not Enabled, Inactive, Timing Out, Active Trip,
Latched Trip.
UNDERFREQUENCY
PICKUP: Not Enabled
Range: Not Enabled, Inactive, Timing Out, Active Trip,
Latched Trip.
OVERFREQUENCY
PICKUP: Not Enabled
Range: Not Enabled, Inactive, Timing Out, Active Trip,
Latched Trip.
489 Generator Management Relay
5-7
5
5.2 A1 STATUS
5 ACTUAL VALUES
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
5
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
5-8
NEUTRAL O/V (FUND)
PICKUP: Not Enabled
Range: Not Enabled, Inactive, Timing Out, Active Trip,
Latched Trip.
NEUTRAL U/V (3rd)
PICKUP: Not Enabled
Range: Not Enabled, Inactive, Timing Out, Active Trip,
Latched Trip.
LOSS OF EXCITATION 1
PICKUP: Not Enabled
Range: Not Enabled, Inactive, Timing Out, Active Trip,
Latched Trip.
LOSS OF EXCITATION 2
PICKUP: Not Enabled
Range: Not Enabled, Inactive, Timing Out, Active Trip,
Latched Trip.
DISTANCE ZONE 1
PICKUP: Not Enabled
Range: Not Enabled, Inactive, Timing Out, Active Trip,
Latched Trip.
DISTANCE ZONE 2
PICKUP: Not Enabled
Range: Not Enabled, Inactive, Timing Out, Active Trip,
Latched Trip.
REACTIVE POWER
PICKUP: Not Enabled
Range: Not Enabled, Inactive, Timing Out, Active Trip,
Latched Trip.
REVERSE POWER
PICKUP: Not Enabled
Range: Not Enabled, Inactive, Timing Out, Active Trip,
Latched Trip.
LOW FORWARD POWER
PICKUP: Not Enabled
Range: Not Enabled, Inactive, Timing Out, Active Trip,
Latched Trip.
RTD #1
PICKUP: Not Enabled
Range: Not Enabled, Inactive, Timing Out, Active Trip,
Latched Trip.
RTD #2
PICKUP: Not Enabled
Range: Not Enabled, Inactive, Timing Out, Active Trip,
Latched Trip.
RTD #3
PICKUP: Not Enabled
Range: Not Enabled, Inactive, Timing Out, Active Trip,
Latched Trip.
RTD #4
PICKUP: Not Enabled
Range: Not Enabled, Inactive, Timing Out, Active Trip,
Latched Trip.
RTD #5
PICKUP: Not Enabled
Range: Not Enabled, Inactive, Timing Out, Active Trip,
Latched Trip.
RTD #6
PICKUP: Not Enabled
Range: Not Enabled, Inactive, Timing Out, Active Trip,
Latched Trip.
RTD #7
PICKUP: Not Enabled
Range: Not Enabled, Inactive, Timing Out, Active Trip,
Latched Trip.
RTD #8
PICKUP: Not Enabled
Range: Not Enabled, Inactive, Timing Out, Active Trip,
Latched Trip.
RTD #9
PICKUP: Not Enabled
Range: Not Enabled, Inactive, Timing Out, Active Trip,
Latched Trip.
RTD #10
PICKUP: Not Enabled
Range: Not Enabled, Inactive, Timing Out, Active Trip,
Latched Trip.
RTD #11
PICKUP: Not Enabled
Range: Not Enabled, Inactive, Timing Out, Active Trip,
Latched Trip.
RTD #12
PICKUP: Not Enabled
Range: Not Enabled, Inactive, Timing Out, Active Trip,
Latched Trip.
THERMAL MODEL
PICKUP: Not Enabled
Range: Not Enabled, Inactive, Timing Out, Active Trip,
Latched Trip.
489 Generator Management Relay
GE Multilin
5 ACTUAL VALUES
5.2 A1 STATUS
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ANALOG I/P 1
PICKUP: Not Enabled
Range: Not Enabled, Inactive, Timing Out, Active Trip,
Latched Trip. Reflects programmed Analog Input
Name. Seen only if input is enabled.
ANALOG I/P 2
PICKUP: Not Enabled
Range: see ANALOG I/P 1 above
ANALOG I/P 3
PICKUP: Not Enabled
Range: see ANALOG I/P 1 above
ANALOG I/P 4
PICKUP: Not Enabled
Range: see ANALOG I/P 1 above
The trip pickup messages may be very useful during testing. They will indicate if a trip feature has been enabled, if it is inactive (not picked up), timing out (picked up and timing), active trip (still picked up, timed out, and causing a trip), or latched tip
(no longer picked up, but had timed out and caused a trip that is latched). These values may also be particularly useful as
data transmitted to a master device for monitoring.
5.2.5 ALARM PICKUPS
PATH: ACTUAL VALUES  A1 STATUS  ALARM PICKUPS
ð
 ALARM PICKUPS
 [ENTER] for more
ENTER
Range: Not Enabled, Inactive, Timing Out, Active Alarm,
Latched Alarm. Reflects Input Name as
programmed. Seen only if function is an input.
PICKUP: Not Enabled
ESCAPE
Input B
PICKUP: Not Enabled
Range: see Input A PICKUP
Input C
PICKUP: Not Enabled
Range: see Input A PICKUP
Input D
PICKUP: Not Enabled
Range: see Input A PICKUP
Input E
PICKUP: Not Enabled
Range: see Input A PICKUP
Input F
PICKUP: Not Enabled
Range: see Input A PICKUP
Input G
PICKUP: Not Enabled
Range: see Input A PICKUP
Input G ALARM
STATUS: Active
Range: see Input A PICKUP
TACHOMETER
PICKUP: Not Enabled
Range: Not Enabled, Inactive, Timing Out, Active Alarm,
Latched Alarm. Seen only if function is an input.
OVERCURRENT
PICKUP: Not Enabled
Range: Not Enabled, Inactive, Timing Out, Active Alarm,
Latched Alarm.
NEG. SEQ. OVERCURRENT
PICKUP: Not Enabled
Range: Not Enabled, Inactive, Timing Out, Active Alarm,
Latched Alarm.
GROUND OVERCURRENT
PICKUP: Not Enabled
Range: Not Enabled, Inactive, Timing Out, Active Alarm,
Latched Alarm.
PHASE DIFFERENTIAL
PICKUP: Not Enabled
Range: Not Enabled, Inactive, Timing Out, Active Alarm,
Latched Alarm.
GROUND DIRECTIONAL
PICKUP: Not Enabled
Range: Not Enabled, Inactive, Timing Out, Active Alarm,
Latched Alarm.
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
GE Multilin
ð Input A
ESCAPE
489 Generator Management Relay
5
5-9
5.2 A1 STATUS
5 ACTUAL VALUES
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
5
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
5-10
UNDERVOLTAGE
PICKUP: Not Enabled
Range: Not Enabled, Inactive, Timing Out, Active Alarm,
Latched Alarm.
OVERVOLTAGE
PICKUP: Not Enabled
Range: Not Enabled, Inactive, Timing Out, Active Alarm,
Latched Alarm.
VOLTS/HERTZ
PICKUP: Not Enabled
Range: Not Enabled, Inactive, Timing Out, Active Alarm,
Latched Alarm.
UNDERFREQUENCY
PICKUP: Not Enabled
Range: Not Enabled, Inactive, Timing Out, Active Alarm,
Latched Alarm.
OVERFREQUENCY
PICKUP: Not Enabled
Range: Not Enabled, Inactive, Timing Out, Active Alarm,
Latched Alarm.
NEUTRAL O/V (FUND)
PICKUP: Not Enabled
Range: Not Enabled, Inactive, Timing Out, Active Alarm,
Latched Alarm.
NEUTRAL U/V (3rd)
PICKUP: Not Enabled
Range: Not Enabled, Inactive, Timing Out, Active Alarm,
Latched Alarm.
REACTIVE POWER
PICKUP: Not Enabled
Range: Not Enabled, Inactive, Timing Out, Active Alarm,
Latched Alarm.
REVERSE POWER
PICKUP: Not Enabled
Range: Not Enabled, Inactive, Timing Out, Active Alarm,
Latched Alarm.
LOW FORWARD POWER
PICKUP: Not Enabled
Range: Not Enabled, Inactive, Timing Out, Active Alarm,
Latched Alarm.
RTD #1
PICKUP: Not Enabled
Range: Not Enabled, Inactive, Timing Out, Active Alarm,
Latched Alarm.
RTD #2
PICKUP: Not Enabled
Range: Not Enabled, Inactive, Timing Out, Active Alarm,
Latched Alarm.
RTD #3
PICKUP: Not Enabled
Range: Not Enabled, Inactive, Timing Out, Active Alarm,
Latched Alarm.
RTD #4
PICKUP: Not Enabled
Range: Not Enabled, Inactive, Timing Out, Active Alarm,
Latched Alarm.
RTD #5
PICKUP: Not Enabled
Range: Not Enabled, Inactive, Timing Out, Active Alarm,
Latched Alarm.
RTD #6
PICKUP: Not Enabled
Range: Not Enabled, Inactive, Timing Out, Active Alarm,
Latched Alarm.
RTD #7
PICKUP: Not Enabled
Range: Not Enabled, Inactive, Timing Out, Active Alarm,
Latched Alarm.
RTD #8
PICKUP: Not Enabled
Range: Not Enabled, Inactive, Timing Out, Active Alarm,
Latched Alarm.
RTD #9
PICKUP: Not Enabled
Range: Not Enabled, Inactive, Timing Out, Active Alarm,
Latched Alarm.
RTD #10
PICKUP: Not Enabled
Range: Not Enabled, Inactive, Timing Out, Active Alarm,
Latched Alarm.
RTD #11
PICKUP: Not Enabled
Range: Not Enabled, Inactive, Timing Out, Active Alarm,
Latched Alarm.
RTD #12
PICKUP: Not Enabled
Range: Not Enabled, Inactive, Timing Out, Active Alarm,
Latched Alarm.
489 Generator Management Relay
GE Multilin
5 ACTUAL VALUES
5.2 A1 STATUS
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
OPEN SENSOR
PICKUP: Not Enabled
Range: Not Enabled, Inactive, Timing Out, Active Alarm,
Latched Alarm.
SHORT/LOW TEMP
PICKUP: Not Enabled
Range: Not Enabled, Inactive, Timing Out, Active Alarm,
Latched Alarm.
THERMAL MODEL
PICKUP: Not Enabled
Range: Not Enabled, Inactive, Timing Out, Active Alarm,
Latched Alarm.
TRIP COUNTER
PICKUP: Not Enabled
Range: Not Enabled, Inactive, Timing Out, Active Alarm,
Latched Alarm.
BREAKER FAILURE
PICKUP: Not Enabled
Range: Not Enabled, Inactive, Timing Out, Active Alarm,
Latched Alarm.
TRIP COIL MONITOR
PICKUP: Not Enabled
Range: Not Enabled, Inactive, Timing Out, Active Alarm,
Latched Alarm.
VT FUSE FAILURE
PICKUP: Not Enabled
Range: Not Enabled, Inactive, Timing Out, Active Alarm,
Latched Alarm.
CURRENT DEMAND
PICKUP: Not Enabled
Range: Not Enabled, Inactive, Timing Out, Active Alarm,
Latched Alarm.
MW DEMAND
PICKUP: Not Enabled
Range: Not Enabled, Inactive, Timing Out, Active Alarm,
Latched Alarm.
Mvar DEMAND
PICKUP: Not Enabled
Range: Not Enabled, Inactive, Timing Out, Active Alarm,
Latched Alarm.
MVA DEMAND
PICKUP: Not Enabled
Range: Not Enabled, Inactive, Timing Out, Active Alarm,
Latched Alarm.
ANALOG I/P 1
PICKUP: Not Enabled
Range: Not Enabled, Inactive, Timing Out, Active Alarm,
Latched Alarm. Reflects programmed Analog
Input Name. Seen only if input is enabled.
ANALOG I/P 2
PICKUP: Not Enabled
Range: see ANALOG I/P 1 PICKUP
ANALOG I/P 3
PICKUP: Not Enabled
Range: see ANALOG I/P 1 PICKUP
ANALOG I/P 4
PICKUP: Not Enabled
Range: see ANALOG I/P 1 PICKUP
The alarm pickup messages may be very useful during testing. They will indicate if a alarm feature has been enabled, if it is
inactive (not picked up), timing out (picked up and timing), active alarm (still picked up, timed out, and causing an alarm), or
latched alarm (no longer picked up, but had timed out and caused a alarm that is latched). These values may also be particularly useful as data transmitted to a master device for monitoring.
GE Multilin
489 Generator Management Relay
5-11
5
5.2 A1 STATUS
5 ACTUAL VALUES
5.2.6 DIGITAL INPUTS
PATH: ACTUAL VALUES  A1 STATUS  DIGITAL INPUTS
ð
 DIGITAL INPUTS
 [ENTER] for more
ENTER
Range: Open, Shorted
SWITCH STATE: Open
ESCAPE
BREAKER STATUS
SWITCH STATE: Open
Range: Open, Shorted
ASSIGNABLE DIGITAL
INPUT1 STATE: Open
Range: Open, Shorted
ASSIGNABLE DIGITAL
INPUT2 STATE: Open
Range: Open, Shorted
ASSIGNABLE DIGITAL
INPUT3 STATE: Open
Range: Open, Shorted
ASSIGNABLE DIGITAL
INPUT4 STATE: Open
Range: Open, Shorted
ASSIGNABLE DIGITAL
INPUT5 STATE: Open
Range: Open, Shorted
ASSIGNABLE DIGITAL
INPUT6 STATE: Open
Range: Open, Shorted
ASSIGNABLE DIGITAL
INPUT7 STATE: Open
Range: Open, Shorted
TRIP COIL
SUPERVISION: No Coil
Range: Open, Shorted
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
5
ð ACCESS
ESCAPE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
The messages shown here may be used to monitor digital input status. This may be useful during relay testing or during
installation.
5.2.7 REAL TIME CLOCK
PATH: ACTUAL VALUES  A1 STATUS  REAL TIME CLOCK
ð
 REAL TIME CLOCK
 [ENTER] for more
ENTER
ESCAPE
ð DATE: 01/01/1995
Range: 01/01/1995 to 12/31/2094, 00:00:00 to 23:59:59
TIME: 12:00:00
The time and date from the 489 real time clock may be viewed here.
5-12
489 Generator Management Relay
GE Multilin
5 ACTUAL VALUES
5.3 A2 METERING DATA
5.3A2 METERING DATA
5.3.1 CURRENT METERING
PATH: ACTUAL VALUES  A2 METERING DATA  CURRENT METERING
ð
 CURRENT METERING
 [ENTER] for more
Range: 0 to 999999 A
ð A:
ESCAPE
C:
0
0
B:
Amps
ESCAPE
a:
c:
0
0
b:
0
Neut. Amps
Range: 0 to 999999 A
a:
c:
0
0
b:
0
Diff. Amps
Range: 0 to 999999 A
ENTER
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
0
AVERAGE PHASE
CURRENT: 0 Amps
Range: 0 to 999999 A
GENERATOR LOAD:
0% FLA
Range: 0 to 2000% FLA
NEGATIVE SEQUENCE
CURRENT: 0% FLA
Range: 0 to 2000% FLA
PHASE A CURRENT:
0 A
0° Lag
Range: 0 to 999999 A, 0 to 359°
PHASE B CURRENT:
0 A
0° Lag
Range: 0 to 999999 A, 0 to 359°
PHASE C CURRENT:
0 A
0° Lag
Range: 0 to 999999 A, 0 to 359°
NEUT. END A CURRENT:
0 A
0° Lag
Range: 0 to 999999 A, 0 to 359°
NEUT. END B CURRENT:
0 A
0° Lag
Range: 0 to 999999 A, 0 to 359°
NEUT. END C CURRENT:
0 A
0° Lag
Range: 0 to 999999 A, 0 to 359°
DIFF. A CURRENT:
0 A
0° Lag
Range: 0 to 999999 A, 0 to 359°
DIFF. B CURRENT:
0 A
0° Lag
Range: 0 to 999999 A, 0 to 359°
DIFF. C CURRENT:
0 A
0° Lag
Range: 0 to 999999 A, 0 to 359°
GROUND CURRENT:
0.0 A
0° Lag
Range: 0.0 to 200000.0 A, 0 to 359°
Seen only if 1 A Ground CT input is used
GROUND CURRENT:
0.00 A
0° Lag
Range: 0.00 to 100.00 A, 0 to 359°
Seen only if 50:0.025 Ground CT is used
5
All measured current values are displayed here. A, B, C AMPS represent the output side CT measurements: A, B, C NEUT.
the neutral end CT measurements, and A, B, C DIFF. AMPS the differential operating current calculated as the vector
difference between the output side and the neutral end CT measurements on a per phase basis. The 489 negativesequence current is defined as the ratio of negative-sequence current to generator rated FLA, I2 / FLA × 100%. The generator full load amps is calculated as: generator rated MVA / ( 3 × generator phase-phase voltage). Polar coordinates for
measured currents are also shown using Va (wye connection) or Vab (open delta connection) as a zero angle reference
vector. In the absence of a voltage signal (Va or Vab), the IA output current is used as the zero angle reference vector.
AMPS
GE Multilin
489 Generator Management Relay
5-13
5.3 A2 METERING DATA
5 ACTUAL VALUES
5.3.2 VOLTAGE METERING
PATH: ACTUAL VALUES  A2 METERING DATA  VOLTAGE METERING
ð
 VOLTAGE METERING
 [ENTER] for more
ENTER
0
0
Vbc:
Volts
Vca:
ESCAPE
AVERAGE LINE
VOLTAGE: 0 Volts
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
5
ð Vab:
ESCAPE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
Van:
Vcn:
0
0
Vbn:
Volts
0
Range: 0 to 50000 V. Not seen if VT CONNECTION is
programmed as None.
Range: 0 to 50000 V. Not seen if VT CONNECTION is
programmed as None.
0
Range: 0 to 50000 V. Seen only if VT CONNECTION is
programmed as Wye.
AVERAGE PHASE
VOLTAGE: 0 Volts
Range: 0 to 50000 V. Seen only if VT CONNECTION is
programmed as Wye.
LINE A-B VOLTAGE:
0 V
0° Lag
Range: 0 to 50000 V, 0 to 359°. Not seen if VT
CONNECTION is programmed as None.
LINE B-C VOLTAGE:
0 V
0° Lag
Range: 0 to 50000 V, 0 to 359°. Not seen if VT
CONNECTION is programmed as None.
LINE C-A VOLTAGE:
0 V
0° Lag
Range: 0 to 50000 V, 0 to 359°. Not seen if VT
CONNECTION is programmed as None.
PHASE A-N VOLTAGE:
0 V
0° Lag
Range: 0 to 50000 V, 0 to 359°. Seen only if VT
CONNECTION is programmed as Wye.
PHASE B-N VOLTAGE:
0 V
0° Lag
Range: 0 to 50000 V, 0 to 359°. Seen only if VT
CONNECTION is programmed as Wye.
PHASE C-N VOLTAGE:
0 V
0° Lag
Range: 0 to 50000 V, 0 to 359°. Seen only if VT
CONNECTION is programmed as Wye.
PER UNIT MEASUREMENT
OF V/Hz: 0.00
Range: 0.00 to 2.00. Not seen if VT CONNECTION is
programmed as None.
FREQUENCY:
0.00 Hz
Range: 0.00 to 90.00 Hz. Not seen if VT CONNECTION
is programmed as None.
NEUTRAL VOLTAGE
FUND: 0.0 V
Range: 0.0 to 25000.0 V. Seen only if there is a neutral
voltage transformer.
NEUTRAL VOLTAGE
3rd HARM: 0.0 V
Range: 0.0 to 25000.0 V. Seen only if there is a neutral
voltage transformer.
TERMINAL VOLTAGE
3rd HARM: 0.0 V
Range: 0.0 to 25000.0 V. Seen only if VT CONNECTION
is programmed as Wye.
IMPEDANCE Vab / Iab
0.0 Ω sec.
0°
Range: 0.0 to 6553.5 Ωsec., 0 to 359°
Measured voltage parameters will be displayed here. The V/Hz measurement is a per unit value based on Vab voltage/
measured frequency divided by VT nominal/nominal system frequency. Polar coordinates for measured phase and/or line
voltages are also shown using Va (wye connection) or Vab (open delta connection) as a zero angle reference vector. In the
absence of a voltage signal (Va or Vab), IA output current is used as the zero angle reference vector.
If VT CONNECTION TYPE is programmed as "None" and NEUTRAL VOLTAGE TRANSFORMER is "No" in S2 SYSTEM, the following flash message will appear when an attempt is made to enter this group of messages.
THIS FEATURE
NOT PROGRAMMED
5-14
489 Generator Management Relay
GE Multilin
5 ACTUAL VALUES
5.3 A2 METERING DATA
5.3.3 POWER METERING
PATH: ACTUAL VALUES  A2 METERING DATA  POWER METERING
ð
 POWER METERING
 [ENTER] for more
ENTER
ð POWER FACTOR:
Range: 0.01 to 0.99 Lead or Lag, 0.00, 1.00
ESCAPE
0.00
ESCAPE
REAL POWER:
0.000 MW
Range: 0.000 to ±2000.000 MW
REACTIVE POWER:
0.000 Mvar
Range: 0.000 to ±2000.000 Mvar
APPARENT POWER:
0.000 MVA
Range: 0.000 to 2000.000 MVA
POSITIVE WATTHOURS:
0.000 MWh
Range: 0.000 to 4000000.000 MWh
POSITIVE VARHOURS:
0.000 Mvarh
Range: 0.000 to 4000000.000 Mvarh
NEGATIVE VARHOURS:
0.000 Mvarh
Range: 0.000 to 4000000.000 Mvarh
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
The values for power metering appear here. Three-phase total power quantities are displayed here. Watthours and varhours are also shown here. Watthours and varhours will not update if a digital input programmed as Test Input is shorted.
An induction generator, by convention generates Watts and consumes vars (+Watts and –vars). A synchronous generator can also generate vars (+vars).
NOTE
If the VT CONNECTION TYPE is programmed as "None", the THIS FEATURE NOT PROGRAMMED flash message will appear
when an attempt is made to enter this group of messages.
GE Multilin
489 Generator Management Relay
5-15
5
5.3 A2 METERING DATA
5 ACTUAL VALUES
5.3.4 TEMPERATURE
PATH: ACTUAL VALUES  A2 METERING DATA  TEMPERATURE
ð
 TEMPERATURE
 [ENTER] for more
ENTER
Range: –50 to 250°C, No RTD
Seen only if at least 1 RTD programmed as
Stator
RTD#1: 40°C
ESCAPE
RTD #1
TEMPERATURE: 40°C
Range: –50 to 250°C, No RTD. Not seen if RTD
programmed as None. Value reflects the RTD
Name as programmed
RTD #2
TEMPERATURE: 40°C
Range: see RTD #1 TEMPERATURE above
RTD #3
TEMPERATURE: 40°C
Range: see RTD #1 TEMPERATURE above
RTD #4
TEMPERATURE: 40°C
Range: see RTD #1 TEMPERATURE above
RTD #5
TEMPERATURE: 40°C
Range: see RTD #1 TEMPERATURE above
RTD #6
TEMPERATURE: 40°C
Range: see RTD #1 TEMPERATURE above
RTD #7
TEMPERATURE: 40°C
Range: see RTD #1 TEMPERATURE above
RTD #8
TEMPERATURE: 40°C
Range: see RTD #1 TEMPERATURE above
RTD #9
TEMPERATURE: 40°C
Range: see RTD #1 TEMPERATURE above
RTD #10
TEMPERATURE: 40°C
Range: see RTD #1 TEMPERATURE above
RTD #11
TEMPERATURE: 40°C
Range: see RTD #1 TEMPERATURE above
RTD #12
TEMPERATURE: 40°C
Range: see RTD #1 TEMPERATURE above
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
5
ð HOTTEST STATOR RTD
ESCAPE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
The current level of the 12 RTDs will be displayed here. If the RTD is not connected, the value will be "No RTD". If no RTDs
are programmed in the S7 RTD TEMPERATURE setpoints menu, the THIS FEATURE NOT PROGRAMMED flash message will
appear when an attempt is made to enter this group of messages.
5-16
489 Generator Management Relay
GE Multilin
5 ACTUAL VALUES
5.3 A2 METERING DATA
5.3.5 DEMAND METERING
PATH: ACTUAL VALUES  A2 METERING DATA  DEMAND METERING
ð
 DEMAND METERING
 [ENTER] for more
ENTER
ð CURRENT
Range: 0 to 999999 A
ESCAPE
DEMAND: 0 Amps
ESCAPE
MW DEMAND:
0.000 MW
Range: 0.000 to 2000.000 MW. Not seen if VT
CONNECTION TYPE is programmed as None
Mvar DEMAND:
0.000 Mvar
Range: 0.000 to 2000.000 Mvar. Not seen if VT
CONNECTION TYPE is programmed as None
MVA DEMAND:
0.000 MVA
Range: 0.000 to 2000.000 MVA. Not seen if VT
CONNECTION TYPE is programmed as None
PEAK CURRENT
DEMAND: 0 Amps
Range: 0 to 999999 A
PEAK MW DEMAND:
0.000 MW
Range: 0.000 to 2000.000 MW. Not seen if VT
CONNECTION TYPE is programmed as None
PEAK Mvar DEMAND:
0.000 Mvar
Range: 0.000 to 2000.000 Mvar. Not seen if VT
CONNECTION TYPE is programmed as None
PEAK MVA DEMAND:
0.000 MVA
Range: 0.000 to 2000.000 MVA. Not seen if VT
CONNECTION TYPE is programmed as None
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
The values for current and power demand are shown here. This peak demand information can be cleared using the S1 489
 CLEAR DATA  CLEAR PEAK DEMAND setpoint. Demand is shown only for positive real and positive reactive
power (+Watts, +vars). Peak demand will not update if a digital input programmed as Test Input is shorted.
SETUP
5.3.6 ANALOG INPUTS
PATH: ACTUAL VALUES  A2 METERING DATA  ANALOG INPUTS
ð
 ANALOG INPUTS
 [ENTER] for more
ENTER
ð ANALOG I/P 1
Range: –50000 to 50000. Message seen only if Analog
Input is programmed. Message reflects Analog
Input Name as programmed.
ESCAPE
0 Units
ESCAPE
ANALOG I/P 2
0 Units
Range: as for ANALOG I/P 1 above
ANALOG I/P 3
0 Units
Range: as for ANALOG I/P 1 above
ANALOG I/P 4
0 Units
Range: as for ANALOG I/P 1 above
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
The values for analog inputs are shown here. The name of the input and the units will reflect those programmed for each
input. If no analog inputs are programmed in the S11 ANALOG I/O setpoints page, the THIS FEATURE NOT PROGRAMMED
flash message will appear when an attempt is made to enter this group of messages.
5.3.7 SPEED
PATH: ACTUAL VALUES  A2 METERING DATA  SPEED
ð
 SPEED
 [ENTER] for more
ENTER
ESCAPE
ð TACHOMETER: 0 RPM
Range: 0 to 7200 RPM. Seen only if a digital input is
configured as Tachometer.
If the Tachometer function is assigned to one of the digital inputs, its speed be viewed here. A bar graph on the second line
of this message represents speed from 0 RPM to rated speed. If no digital input is configured for tachometer, the THIS FEATURE NOT PROGRAMMED flash message will appear when an attempt is made to enter this group of messages.
GE Multilin
489 Generator Management Relay
5-17
5
5.4 A3 LEARNED DATA
5 ACTUAL VALUES
5.4A3 LEARNED DATA
5.4.1 PARAMETER AVERAGES
PATH: ACTUAL VALUES  A3 LEARNED DATA  PARAMETER AVERAGES
ð
 PARAMETER AVERAGES
 [ENTER] for more
ð AVERAGE GENERATOR
Range: 0 to 2000% FLA
ESCAPE
LOAD: 100% FLA
ESCAPE
AVERAGE NEG. SEQ.
CURRENT: 0% FLA
Range: 0 to 2000% FLA
AVERAGE PHASE-PHASE
VOLTAGE:
0 V
Range: 0 to 50000 V. Not seen if VT CONNECTION is
programmed as None
ENTER
MESSAGE
ESCAPE
MESSAGE
The 489 calculates the average magnitude of several parameters over a period of time. This time is specified by S1 489
SETUP  PREFERENCES  PARAMETER AVERAGES CALC. PERIOD setpoint (default 15 minutes). The calculation is a sliding window and is ignored when the generator is offline (that is, the value that was calculated just prior to going offline will
be held until the generator is brought back online and a new calculation is made). Parameter averages will not update if a
digital input programmed as Test Input is shorted.
5.4.2 RTD MAXIMUMS
PATH: ACTUAL VALUES  A3 LEARNED DATA  RTD MAXIMUMS
5
ð
 RTD MAXIMUMS
 [ENTER] for more
ENTER
ð RTD #1
Range: –50 to 250°C. Not seen if RTD programmed as
None. The first line of this message reflects the
RTD Name as programmed.
ESCAPE
MAX. TEMP.: 40°C
ESCAPE
RTD #2
MAX. TEMP.: 40°C
Range: as for RTD #1 above
RTD #3
MAX. TEMP.: 40°C
Range: as for RTD #1 above
RTD #4
MAX. TEMP.: 40°C
Range: as for RTD #1 above
RTD #5
MAX. TEMP.: 40°C
Range: as for RTD #1 above
RTD #6
MAX. TEMP.: 40°C
Range: as for RTD #1 above
RTD #7
MAX. TEMP.: 40°C
Range: as for RTD #1 above
RTD #8
MAX. TEMP.: 40°C
Range: as for RTD #1 above
RTD #9
MAX. TEMP.: 40°C
Range: as for RTD #1 above
RTD #10
MAX. TEMP.: 40°C
Range: as for RTD #1 above
RTD #11
MAX. TEMP.: 40°C
Range: as for RTD #1 above
RTD #12
MAX. TEMP.: 40°C
Range: as for RTD #1 above
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
The 489 will learn the maximum temperature for each RTD. This information can be cleared using the S1 489 SETUP 
CLEAR DATA  CLEAR RTD MAXIMUMS setpoint. The RTD maximums will not update if a digital input programmed as Test
Input is shorted. If no RTDs are programmed in the S7 RTD TEMPERATURE setpoints page, the THIS FEATURE NOT PROGRAMMED flash message will appear when an attempt is made to enter this group of messages.
5-18
489 Generator Management Relay
GE Multilin
5 ACTUAL VALUES
5.4 A3 LEARNED DATA
5.4.3 ANALOG INPUT MINIMUM/MAXIMUM
PATH: ACTUAL VALUES  A3 LEARNED DATA  ANALOG IN MIN/MAX
ð
 ANALOG IN MIN/MAX
 [ENTER] for more
ENTER
ð ANALOG I/P 1
Range: –50000 to 50000. Not seen if Analog Input is
programmed as None. Message reflects Analog
Input Name as programmed.
ESCAPE
MIN: O Units
ESCAPE
ANALOG I/P 1
MAX: 0 Units
Range: as for ANALOG I/P 1 MIN above
ANALOG I/P 2
MIN: O Units
Range: as for ANALOG I/P 1 MIN above
ANALOG I/P 2
MAX: 0 Units
Range: as for ANALOG I/P 1 MIN above
ANALOG I/P 3
MIN: O Units
Range: as for ANALOG I/P 1 MIN above
ANALOG I/P 3
MAX: 0 Units
Range: as for ANALOG I/P 1 MIN above
ANALOG I/P 4
MIN: O Units
Range: as for ANALOG I/P 1 MIN above
ANALOG I/P 4
MAX: 0 Units
Range: as for ANALOG I/P 1 MIN above
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
The 489 learns the minimum and maximum values of the analog inputs since they were last cleared. This information can
be cleared using the S1 489 SETUP  CLEAR DATA  CLEAR ANALOG I/P MIN/MAX setpoint. When the data is cleared, the
present value of each analog input will be loaded as a starting point for both minimum and maximum. The name of the input
and the units will reflect those programmed for each input. Analog Input minimums and maximums will not update if a digital
input programmed as Test Input is shorted.
If no Analog Inputs are programmed in the S11 ANALOG I/O setpoints menu, the THIS FEATURE NOT PROGRAMMED flash
message will appear when an attempt is made to enter this group of messages.
GE Multilin
489 Generator Management Relay
5-19
5
5.5 A4 MAINTENANCE
5 ACTUAL VALUES
5.5A4 MAINTENANCE
5.5.1 TRIP COUNTERS
PATH: ACTUAL VALUES  A4 MAINTENANCE  TRIP COUNTERS
ð
 TRIP COUNTERS
 [ENTER] for more
ENTER
ESCAPE
DIGITAL INPUT
TRIPS: 0
Range: 0 to 50000
Caused by the General Input Trip feature
SEQUENTIAL
TRIPS: 0
Range: 0 to 50000
FIELD-BKR DISCREP.
TRIPS: 0
Range: 0 to 50000
TACHOMETER
TRIPS: 0
Range: 0 to 50000
OFFLINE OVERCURRENT
TRIPS: 0
Range: 0 to 50000
PHASE OVERCURRENT
TRIPS: 0
Range: 0 to 50000
NEG. SEQ. OVERCURRENT
TRIPS: 0
Range: 0 to 50000
GROUND OVERCURRENT
TRIPS: 0
Range: 0 to 50000
PHASE DIFFERENTIAL
TRIPS: 0
Range: 0 to 50000
GROUND DIRECTIONAL
TRIPS: 0
Range: 0 to 50000
HIGH-SET PHASE O/C
TRIPS: 0
Range: 0 to 50000
UNDERVOLTAGE
TRIPS: 0
Range: 0 to 50000
OVERVOLTAGE
TRIPS: 0
Range: 0 to 50000
VOLTS/HERTZ
TRIPS: 0
Range: 0 to 50000
PHASE REVERSAL
TRIPS: 0
Range: 0 to 50000
UNDERFREQUENCY
TRIPS: 0
Range: 0 to 50000
OVERFREQUENCY
TRIPS: 0
Range: 0 to 50000
NEUTRAL O/V (Fund)
TRIPS: 0
Range: 0 to 50000
NEUTRAL U/V (3rd)
TRIPS: 0
Range: 0 to 50000
LOSS OF EXCITATION 1
TRIPS: 0
Range: 0 to 50000
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
5-20
Range: 0 to 50000
TRIPS: 0
MESSAGE
5
ð TOTAL NUMBER OF
ESCAPE
489 Generator Management Relay
GE Multilin
5 ACTUAL VALUES
5.5 A4 MAINTENANCE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
LOSS OF EXCITATION 2
TRIPS: 0
Range: 0 to 50000
DISTANCE ZONE 1
TRIPS: 0
Range: 0 to 50000
DISTANCE ZONE 2
TRIPS: 0
Range: 0 to 50000
REACTIVE POWER
TRIPS: 0
Range: 0 to 50000
REVERSE POWER
TRIPS: 0
Range: 0 to 50000
LOW FORWARD POWER
TRIPS: 0
Range: 0 to 50000
STATOR RTD
TRIPS: 0
Range: 0 to 50000
BEARING RTD
TRIPS: 0
Range: 0 to 50000
OTHER RTD
TRIPS: 0
Range: 0 to 50000
AMBIENT RTD
TRIPS: 0
Range: 0 to 50000
THERMAL MODEL
TRIPS: 0
Range: 0 to 50000
INADVERTENT ENERG.
TRIPS: 0
Range: 0 to 50000
ANALOG I/P 1
TRIPS: 0
Range: 0 to 50000
Reflects Analog I/P Name/units as programmed
ANALOG I/P 2
TRIPS: 0
Range: 0 to 50000
Reflects Analog I/P Name/units as programmed
ANALOG I/P 3
TRIPS: 0
Range: 0 to 50000
Reflects Analog I/P Name/units as programmed
ANALOG I/P 4
TRIPS: 0
Range: 0 to 50000
Reflects Analog I/P Name/units as programmed
5
COUNTERS CLEARED:
Jan 1, 1995
The number of trips by type is displayed here. When the total reaches 50000, all counters reset. This information can be
cleared with the S1 489 SETUP  CLEAR DATA  CLEAR TRIP COUNTERS setpoint. Trip counters will not update if a digital
input programmed as Test Input is shorted. In the event of multiple trips, the only the first trip will increment the trip counters.
GE Multilin
489 Generator Management Relay
5-21
5.5 A4 MAINTENANCE
5 ACTUAL VALUES
5.5.2 GENERAL COUNTERS
PATH: ACTUAL VALUES  A4 MAINTENANCE  GENERAL COUNTERS
ð
 GENERAL COUNTERS
 [ENTER] for more
ENTER
ESCAPE
ESCAPE
MESSAGE
Range: 0 to 50000
ð NUMBER OF BREAKER
OPERATIONS: 0
Range: 0 to 50000. Seen only if a digital input is assigned
to Thermal Reset.
NUMBER OF THERMAL
RESETS: 0
One of the 489 general counters will count the number of breaker operations over time. This may be useful information for
breaker maintenance. The number of breaker operations is incremented whenever the breaker status changes from closed
to open and all phase currents are zero. Another counter counts the number of thermal resets if one of the assignable digital inputs is assigned to thermal reset. This may be useful information when troubleshooting. When either of these counters
reaches 50000, that counter will reset to 0. Each counter can also be cleared using the S1 489 SETUP  CLEAR DATA 
CLEAR BREAKER INFORMATION setpoint. The number of breaker operations will not update if a digital input programmed as
Test Input is shorted.
5.5.3 TIMERS
PATH: ACTUAL VALUES  A4 MAINTENANCE  TIMERS
5
ð
 TIMERS
 [ENTER] for more
ENTER
ESCAPE
ð GENERATOR HOURS
ONLINE:
Range: 1 to 1000000 hrs.
0 h
The 489 accumulates the total online time for the generator. This may be useful for scheduling routine maintenance. When
this timer reaches 1000000, it resets to 0. This timer can be cleared using the S1 489 SETUP  CLEAR DATA  CLEAR
GENERATOR INFORMATION setpoint. The generator hours online will not update if a digital input programmed as Test Input is
shorted.
5-22
489 Generator Management Relay
GE Multilin
5 ACTUAL VALUES
5.6 A5 EVENT RECORDER
5.6A5 EVENT RECORDER
5.6.1 EVENT RECORDER
PATH: ACTUAL VALUES  A5 EVENT RECORDER  [ENTER] EVENT01(40)
ð
 [ENTER] EVENT01
No Event
ð TIME OF EVENT01:
ESCAPE
00:00:00.0
Range: hour:minutes:seconds
Seen only if there has been an event.
ESCAPE
DATE OF EVENT01:
Jan. 01, 1992
Range: month day, year
Seen only if there has been an event.
ACTIVE
GROUP EVENT01: 1
Range: 1, 2
TACHOMETER
EVENT01: 3600 RPM
Range: 0 to 3600 RPM. Seen only if a Digital Input is
programmed as Tachometer
A:
C:
Range: 0 to 999999 A. Represents current measured
from the output CTs. Seen only if there has been
an event.
ENTER
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
GE Multilin
a:
c:
0
0
0
0
B:
0
A EVENT01
b:
A
0
EVENT01
Range: 0 to 999999 A. Represents differential current.
Seen only if the differential element is enabled.
NEG. SEQ. CURRENT
EVENT01: 0% FLA
Range: 0 to 2000% FLA
Seen only if there has been an event.
GROUND CURRENT
EVENT01: 0.00 A
Range: 0.00 to 20000.0 A. Not seen if the GROUND CT
TYPE is programmed as "None".
Vab:
Vca:
Range: 0 to 50000 V. Not seen if VT CONNECTION is
programmed as "None".
0
0
Vbc:
0
V EVENT01
FREQUENCY
EVENT01: 0.00 Hz
Range: 0.00 to 90.00 Hz. Not seen if VT CONNECTION
is programmed as "None".
NEUTRAL VOLT (FUND)
EVENT01:
0.0 V
Range: 0.0 to 25000.0 V. Seen only if there is a neutral
voltage transformer.
NEUTRAL VOLT (3rd)
EVENT01:
0.0 V
Range: 0.0 to 25000.0 V. Seen only if there is a neutral
voltage transformer.
Vab/Iab EVENT01:
0.0 Ωsec.
0°
Range: 0.0 to 6553.5 Ωsec., 0 to 359°. Seen only if the
Loss of Excitation element is Enabled.
REAL POWER (MW)
EVENT01:
0.000
Range: 0.000 to ±2000.000 MW. Not seen if VT
CONNECTION is programmed as "None"
REACTIVE POWER Mvar
EVENT01:
0.000
Range: 0.000 to ±2000.000 Mvar. Not seen if VT
CONNECTION is programmed as "None"
APPARENT POWER MVA
EVENT01:
0.000
Range:0.000 to 2000.000 MVA. Not seen if
CONNECTION is programmed as "None"
HOTTEST STATOR
RTD#1: 0°C EVENT01
Range: –50 to +250°C. Seen only if 1 or more RTDs are
programmed as Stator.
HOTTEST BEARING
RTD#7: 0°C EVENT01
Range: –50 to +250°C. Seen only if 1 or more RTDs are
programmed as Bearing.
HOTTEST OTHER
RTD#11: 0°C EVENT01
Range: –50 to +250°C. Seen only if 1 or more RTDs are
programmed as Other.
AMBIENT
RTD#12 0°C
Range: –50 to +250°C. Seen only if 1 or more RTDs are
programmed as Ambient.
EVENT01
ANALOG INPUT 1
EVENT01: 0.0 Units
VT
Range: –50000 to 50000
Seen only if the Analog Input is in use.
489 Generator Management Relay
5-23
5
5.6 A5 EVENT RECORDER
5 ACTUAL VALUES
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
ANALOG INPUT 2
EVENT01: 0.0 Units
Range: –50000 to 50000
Seen only if the Analog Input is in use.
ANALOG INPUT 3
EVENT01: 0.0 Units
Range: –50000 to 50000
Seen only if the Analog Input is in use.
ANALOG INPUT 4
EVENT01: 0.0 Units
Range: –50000 to 50000
Seen only if the Analog Input is in use.
The 489 Event Recorder stores generator and system information each time an event occurs. The description of the event
is stored and a time and date stamp is also added to the record. This allows reconstruction of the sequence of events for
troubleshooting. Events include: all trips, any alarm optionally (except Service Alarm, and 489 Not Inserted Alarm, which
always records as events), loss of control power, application of control power, thermal resets, simulation, serial communication starts/stops and general input control functions optionally.
EVENT01 is the most recent event and EVENT40 is the oldest event. Each new event bumps the other event records down
until the 40th event is reached. The 40th event record is lost when the next event occurs. This information can be cleared
using S1 489 SETUP  CLEAR DATA  CLEAR EVENT RECORD setpoint. The event record will not update if a digital input
programmed as Test Input is shorted.
Table 5–1: CAUSE OF EVENTS
TRIPS
5
Ambient RTD12 Trip *
Analog I/P 1 to 4 Trip *
Bearing RTD 7 Trip *
Bearing RTD 8 Trip *
Bearing RTD 9 Trip *
Bearing RTD 10 Trip *
Differential Trip
Distance Zone 1 Trip
Distance Zone 2 Trip
Field-Bkr Discr. Trip
Gnd Directional Trip
Ground O/C Trip
Hiset Phase O/C Trip
Input A to G Trip *
Loss of Excitation 1
Loss of Excitation 2
Low Fwd Power Trip
Neg Seq O/C Trip
Neutral O/V Trip
Neut. U/V (3rd) Trip
Offline O/C Trip
Overfrequency Trip
Overvoltage Trip
Phase O/C Trip
Phase Reversal Trip
Reactive Power Trip
Reverse Power Trip
RTD11 Trip *
Sequential Trip
Stator RTD 1 Trip *
Stator RTD 2 Trip *
Stator RTD 3 Trip *
Stator RTD 4 Trip *
Stator RTD 5 Trip *
Stator RTD 6 Trip *
Tachometer Trip
Thermal Model Trip
Underfrequency Trip
Undervoltage Trip
Volts/Hertz Trip
Ambient RTD12 Alarm *
Analog I/P 1 to 4 Alarm *
Bearing RTD 7 Alarm *
Bearing RTD 8 Alarm *
Bearing RTD 9 Alarm *
Bearing RTD 10 Alarm *
Breaker Failure
Current Demand Alarm
Gnd Directional Alarm
Ground O/C Alarm
Input A to G Alarm *
Low Fwd Power Alarm
MVA Alarm
Mvar Alarm
MW Alarm
NegSeq Current Alarm
Neut. U/V 3rd Alarm
Neutral O/V Alarm
Open RTD Alarm
Overcurrent Alarm
Overfrequency Alarm
Overvoltage Alarm
Reactive Power Alarm
Reverse Power Alarm
RTD11 Alarm *
Short/Low RTD Alarm
Stator RTD 1 Alarm
Stator RTD 2 Alarm
Stator RTD 3 Alarm
Stator RTD 4 Alarm
Stator RTD 5 Alarm
Stator RTD 6 Alarm
Tachometer Alarm
Thermal Model Alarm
Trip Coil Monitor
Trip Counter Alarm
Underfrequency Alarm
Undervoltage Alarm
VT Fuse Fail Alarm
489 Not Inserted
Control Power Applied
Control Power Lost
Dig I/P Waveform Trig
Input A to G Control *
IRIG-B Failure
Serial Comm. Start
Serial Comm. Stop
Simulation Started
ALARMS (OPTIONAL EVENTS)
OTHER
*
Serial Waveform Trip
Setpoint 1 Active
Setpoint 2 Active
Simulation Stopped
Thermal Reset Close
Thermal Reset Open
reflects the name that is programmed
5-24
489 Generator Management Relay
GE Multilin
5 ACTUAL VALUES
5.7 A6 PRODUCT INFO
5.7A6 PRODUCT INFO
5.7.1 489 MODEL INFO
PATH: ACTUAL VALUES  A6 PRODUCT INFO  489 MODEL INFO
ð
 489 MODEL INFO
 [ENTER] for more
ENTER
ð ORDER CODE:
Range: N/A
ESCAPE
489-P5-HI-A20
ESCAPE
489 SERIAL NO:
A3260001
Range: N/A
489 REVISION:
32E100A4.000
Range: N/A
489 BOOT REVISION:
32E100A0.000
Range: N/A
MESSAGE
ESCAPE
MESSAGE
ESCAPE
MESSAGE
All of the 489 model information may be viewed here when the unit is powered up. In the event of a product software
upgrade or service question, the information shown here should be jotted down prior to any inquiry.
5.7.2 CALIBRATION INFO
PATH: ACTUAL VALUES  A6 PRODUCT INFO  CALIBRATION INFO
ð
 CALIBRATION INFO
 [ENTER] for more
ð ORIGINAL CALIBRATION
Range: month day year
ESCAPE
DATE: Jan 01 1996
ESCAPE
LAST CALIBRATION
DATE: Jan 01 1996
Range: month day year
ENTER
MESSAGE
5
The date of the original calibration and last calibration may be viewed here.
GE Multilin
489 Generator Management Relay
5-25
5.8 DIAGNOSTICS
5 ACTUAL VALUES
5.8DIAGNOSTICS
5.8.1 DIAGNOSTIC MESSAGES
In the event of a trip or alarm, some of the actual value messages are very helpful in diagnosing the cause of the condition.
The 489 will automatically default to the most important message. The hierarchy is trip and pretrip messages, then alarm
messages. In order to simplify things for the operator, the Message LED (indicator) will flash prompting the operator to
press the NEXT key. When the NEXT key is pressed, the 489 will automatically display the next relevant message and
continue to cycle through the messages with each keypress. When all of these conditions have cleared, the 489 will revert
back to the normal default messages.
Any time the 489 is not displaying the default messages because other actual value or setpoint messages are being viewed
and there are no trips or alarms, the Message LED (indicator) will be on solid. From any point in the message structure,
pressing the NEXT key will cause the 489 to revert back to the normal default messages. When normal default messages
are being displayed, pressing the NEXT key will cause the 489 to display the next default message immediately.
EXAMPLE:
If a thermal model trip occurred, an RTD alarm may also occur as a result of the overload. The 489 would automatically
default to the CAUSE OF LAST TRIP message at the top of the A1 STATUS  LAST TRIP DATA queue and the Message LED
would flash. Pressing the NEXT key cycles through the time and date stamp information as well as all of the pre-trip data.
When the bottom of this queue is reached, an additional press of the NEXT key would normally return to the top of the
queue. However, because there is an alarm active, the display will skip to the alarm message at the top of the A1 STATUS
 ALARM STATUS queue. Finally, another press of the NEXT key will cause the 489 to return to the original CAUSE OF
LAST TRIP message, and the cycle could be repeated.
LAST TRIP DATA:
5
CAUSE OF LAST TRIP:
Overload
TIME OF LAST TRIP:
12:00:00.0
NEXT
DATE OF LAST TRIP
Jan 01 1992
↓
↓
↓
ANALOG INPUT 4
PreTrip: 0 Units
ACTIVE ALARMS:
STATOR RTD #1
ALARM: 135°C
START BLOCK
LOCKOUTS:
OVERLOAD LOCKOUT
BLOCK: 25 min
When the RESET has been pressed and the hot RTD condition is no longer present, the display will revert back to the normal default messages.
5-26
489 Generator Management Relay
GE Multilin
5 ACTUAL VALUES
5.8 DIAGNOSTICS
5.8.2 FLASH MESSAGES
Flash messages are warning, error, or general information messages that are temporarily displayed in response to certain
key presses. These messages are intended to assist with navigation of the 489 messages by explaining what has happened or by prompting the user to perform certain actions.
Table 5–2: FLASH MESSAGES
NEW SETPOINT HAS
BEEN STORED
ROUNDED SETPOINT
HAS BEEN STORED
OUT OF RANGE.! ENTER:
#### TO ##### BY #
ACCESS DENIED,
SHORT ACCESS SWITCH
ACCESS DENIED,
ENTER PASSCODE
INVALID PASSCODE
ENTERED!
NEW PASSCODE
HAS BEEN ACCEPTED
PASSCODE SECURITY
NOT ENABLED, ENTER 0
ENTER A NEW
PASSCODE FOR ACCESS
SETPOINT ACCESS IS
NOW PERMITTED
SETPOINT ACCESS IS
NOW RESTRICTED
DATE ENTRY WAS
NOT COMPLETE
DATE ENTRY
OUT OF RANGE
TIME ENTRY WAS
NOT COMPLETE
TIME ENTRY
OUT OF RANGE
NO TRIPS OR ALARMS
TO RESET
RESET PERFORMED
SUCCESSFULLY
ALL POSSIBLE RESETS
HAVE BEEN PERFORMED
ARE YOU SURE? PRESS
[ENTER] TO VERIFY
PRESS [ENTER] TO ADD
DEFAULT MESSAGE
DEFAULT MESSAGE
HAS BEEN ADDED
DEFAULT MESSAGE
LIST IS FULL
PRESS [ENTER] TO
REMOVE MESSAGE
DEFAULT MESSAGE
HAS BEEN REMOVED
DEFAULT MESSAGES
6 TO 20 ARE ASSIGNED
INVALID SERVICE CODE
ENTERED
KEY PRESSED IS
INVALID HERE
DATA CLEARED
SUCCESSFULLY
[.] KEY IS USED TO
ADVANCE THE CURSOR
TOP OF PAGE
END OF PAGE
TOP OF LIST
END OF LIST
NO ALARMS ACTIVE
THIS FEATURE NOT
PROGRAMMED
THIS PARAMETER IS
ALREADY ASSIGNED
THAT INPUT ALREADY
USED FOR TACHOMETER
TACHOMETER MUST USE
INPUT 4, 5, 6, OR 7
THAT DIGITAL INPUT
IS ALREADY IN USE
•
NEW SETPOINT HAS BEEN STORED: This message appear each time a setpoint has been altered and stored as
shown on the display.
•
ROUNDED SETPOINT HAS BEEN STORED: Since the 489 has a numeric keypad, an entered setpoint value may fall
between valid setpoint values. The 489 detects this condition and store a value rounded to the nearest valid setpoint
value. To find the valid range and step for a given setpoint, press the HELP key while the setpoint is being displayed.
•
OUT OF RANGE! ENTER: #### TO ##### BY #: If a setpoint value outside the acceptable range of values is entered,
the 489 displays this message and substitutes proper values for that setpoint. An appropriate value may then be
entered.
•
ACCESS DENIED, SHORT ACCESS SWITCH: The Access Switch must be shorted to store any setpoint values. If
this message appears and it is necessary to change a setpoint, short the Access terminals C1 and C2.
•
ACCESS DENIED, ENTER PASSCODE: The 489 has a passcode security feature. If this feature is enabled, not only
must the Access Switch terminals be shorted, but a valid passcode must also be entered. If the correct passcode has
been lost or forgotten, contact the factory with the encrypted access code. All passcode features may be found in the
S1 489 SETUP  PASSCODE setpoints menu.
•
INVALID PASSCODE ENTERED: This flash message appears if an invalid passcode is entered for the passcode
security feature.
•
NEW PASSCODE HAS BEEN ACCEPTED: This message will appear as an acknowledge that the new passcode has
been accepted when changing the passcode for the passcode security feature.
•
PASSCODE SECURITY NOT ENABLED, ENTER 0: The passcode security feature is disabled whenever the passcode is zero (factory default). Any attempts to enter a passcode when the feature is disabled results in this flash message, prompting the user to enter "0" as the passcode. When this has been done, the feature may be enabled by
entering a non-zero passcode.
•
ENTER A NEW PASSCODE FOR ACCESS: The passcode security feature is disabled if the passcode is zero. If the
CHANGE PASSCODE SETPOINT is entered as yes, this flash message appears prompting the user to enter a non-zero
passcode and enable the passcode security feature.
•
SETPOINT ACCESS IS NOW PERMITTED: Any time the passcode security feature is enabled and a valid passcode
is entered, this flash message appears to notify that setpoints may now be altered and stored.
GE Multilin
489 Generator Management Relay
5-27
5
5.8 DIAGNOSTICS
5 ACTUAL VALUES
•
SETPOINT ACCESS IS NOW RESTRICTED: If the passcode security feature is enabled and a valid passcode
entered, this message appears when the S1 489 SETUP  PASSCODE  SETPOINT ACCESS setpoint is altered to
"Restricted". This message also appears any time that setpoint access is permitted and the access jumper is removed.
•
DATE ENTRY WAS NOT COMPLETE: Since the DATE setpoint has a special format (entered as MM/DD/YYYY), this
message appears and the new value will not be stored if the ENTER key is pressed before all of the information has
been entered. Another attempt will have to be made with the complete information.
•
DATE ENTRY WAS OUT OF RANGE: Appears if an invalid entry is made for the DATE (for example, 15 entered for the
month).
•
TIME ENTRY WAS NOT COMPLETE: Since the TIME setpoint has a special format (entered as HH/MM/SS.s), this
message appears and the new value will not be stored if the ENTER key is pressed before all of the information has
been entered. Another attempt will have to be made with the complete information.
•
TIME ENTRY WAS OUT OF RANGE: Appears if an invalid entry is made for the TIME (for example, 35 entered for the
hour).
•
NO TRIPS OR ALARMS TO RESET: Appears if the
•
RESET PERFORMED SUCCESSFULLY: If all trip and alarm features that are active can be cleared (that is, the conditions that caused these trips and/or alarms are no longer present), then this message appears when a RESET is performed, indicating that all trips and alarms have been cleared.
•
ALL POSSIBLE RESETS HAVE BEEN PERFORMED: If only some of the trip and alarm features that are active can
be cleared (that is, the conditions that caused some of these trips and/or alarms are still present), then this message
appears when a RESET is performed, indicating that only trips and alarms that could be reset have been reset.
•
ARE YOU SURE? PRESS [ENTER] TO VERIFY: If the RESET key is pressed and resetting of any trip or alarm feature
is possible, this message appears to verify the operation. If RESET is pressed again while this message is displayed,
the reset will be performed.
•
PRESS [ENTER] TO ADD DEFAULT MESSAGE: Appears if the decimal [.] key, immediately followed by the ENTER
key, is entered anywhere in the actual value message structure. This message prompts the user to press ENTER to add
a new default message. To add a new default message, ENTER must be pressed while this message is being displayed.
•
DEFAULT MESSAGE HAS BEEN ADDED: Appears anytime a new default message is added to the default message
list.
•
DEFAULT MESSAGE LIST IS FULL: Appears if an attempt is made to add a new default message to the default message list when 20 messages are already assigned. To add a new message, one of the existing messages must be
removed.
•
PRESS [ENTER] TO REMOVE MESSAGE: Appears if the decimal [.] key, immediately followed by the ENTER key, is
entered in the S1 489 SETUP  DEFAULT MESSAGES setpoint page. This message prompts the user to press ENTER to
remove a default message. To remove the default message, ENTER must be pressed while this message is being displayed.
•
DEFAULT MESSAGE HAS BEEN REMOVED: Appears anytime a default message is removed from the default message list.
•
DEFAULT MESSAGES 6 of 20 ARE ASSIGNED: Appears anytime the S1 489 SETUP  DEFAULT MESSAGES setpoint
page is entered, notifying the user of the number of default messages assigned.
5
•
RESET
key is pressed when there are no trips or alarms present.
INVALID SERVICE CODE ENTERED: Appears if an invalid code is entered in the S12 489 TESTING  FACTORY SERsetpoints page.
VICE
•
KEY PRESSED HERE IS INVALID: Under certain situations, certain keys have no function (for example, any number
key while viewing actual values). This message appears if a keypress has no current function.
•
DATA CLEARED SUCCESSFULLY: Confirms that data is reset in the S1 489 SETUP  CLEAR DATA setpoints page.
•
[.] KEY IS USED TO ADVANCE THE CURSOR: Appears immediately to prompt the use of the [.] key for cursor control anytime a setpoint requiring text editing is viewed. If the setpoint is not altered for 1 minute, this message flashes
again.
•
TOP OF PAGE: This message will indicate when the top of a page has been reached.
•
BOTTOM OF PAGE: This message will indicate when the bottom of a page has been reached.
5-28
489 Generator Management Relay
GE Multilin
5 ACTUAL VALUES
5.8 DIAGNOSTICS
•
TOP OF LIST: This message will indicate when the top of subgroup has been reached.
•
END OF LIST: This message will indicate when the bottom of a subgroup has been reached.
•
NO ALARMS ACTIVE: If an attempt is made to enter the Alarm Status message subgroup, but there are no active
alarms, this message will appear.
•
THIS FEATURE NOT PROGRAMMED: If an attempt is made to enter an actual value message subgroup, when the
setpoints are not configured for that feature, this message will appear.
•
THIS PARAMETER IS ALREADY ASSIGNED: A given analog output parameters can only be assigned to one output.
If an attempt is made to assign a parameter to a second output, this message will appear.
•
THAT INPUT ALREADY USED FOR TACHOMETER: If a digital input is assigned to the tachometer function, it cannot
be used for any other digital input function. If an attempt is made to assign a digital input to a function when it is already
assigned to tachometer, this message will appear.
•
TACHOMETER MUST USE INPUT 4, 5, 6, or 7: Only digital inputs 4, 5, 6, or 7 may be used for the tachometer function. If an attempt is made to assign inputs 1,2,3, or 4 to the tachometer function, this message will appear.
•
THAT DIGITAL INPUT IS ALREADY IN USE: If an attempt is made to assign a digital input to tachometer when it is
already assigned to another function, this message will appear.
•
To edit use VALUE UP or VALUE DOWN key: If a numeric key is pressed on a setpoint parameter that is not
numeric, this message will prompt the user to use the value keys.
•
GROUP 1 SETPOINT HAS BEEN STORED: This message appear each time a setpoint has been altered and stored
to setpoint Group 1 as shown on the display.
•
GROUP 2 SETPOINT HAS BEEN STORED: This message appear each time a setpoint has been altered and stored
to setpoint Group 2 as shown on the display.
GE Multilin
489 Generator Management Relay
5-29
5
5.8 DIAGNOSTICS
5 ACTUAL VALUES
5
5-30
489 Generator Management Relay
GE Multilin
6 COMMUNICATIONS
6.1 MODBUS PROTOCOL
6 COMMUNICATIONS 6.1MODBUS PROTOCOL
6.1.1 ELECTRICAL INTERFACE
The hardware or electrical interface is one of the following: one of two 2-wire RS485 ports from the rear terminal connector
or the RS232 from the front panel connector. In a 2-wire RS485 link, data flow is bidirectional. Data flow is half-duplex for
both the RS485 and the RS232 ports. That is, data is never transmitted and received at the same time. RS485 lines should
be connected in a daisy chain configuration (avoid star connections) with a terminating network installed at each end of the
link, i.e. at the master end and at the slave farthest from the master. The terminating network should consist of a 120 Ω
resistor in series with a 1 nF ceramic capacitor when used with Belden 9841 RS485 wire. The value of the terminating
resistors should be equal to the characteristic impedance of the line. This is approximately 120 Ω for standard #22 AWG
twisted pair wire. Shielded wire should always be used to minimize noise. Polarity is important in RS485 communications.
Each '+' terminal of every 489 must be connected together for the system to operate. See Section 2.2.12: RS485 Communications Ports on page 2–14 for details on correct serial port wiring.
6.1.2 MODBUS RTU DESCRIPTION
The 489 implements a subset of the AEG Modicon Modbus RTU serial communication standard. Many popular programmable controllers support this protocol directly with a suitable interface card allowing direct connection of relays. Although
the Modbus protocol is hardware independent, the 489 interfaces include two 2-wire RS485 ports and one RS232 port.
Modbus is a single master, multiple slave protocol suitable for a multi-drop configuration as provided by RS485 hardware.
In this configuration up to 32 slaves can be daisy-chained together on a single communication channel.
The 489 is always a slave; it cannot be programmed as a master. Computers or PLCs are commonly programmed as masters. The Modbus protocol exists in two versions: Remote Terminal Unit (RTU, binary) and ASCII. Only the RTU version is
supported by the 489. Monitoring, programming, and control functions are performed with read / write register commands.
6.1.3 DATA FRAME FORMAT AND DATA RATE
One data frame of an asynchronous transmission to or from a 489 is default to 1 start bit, 8 data bits, and 1 stop bit. This
produces a 10-bit data frame. This is important for transmission through modems at high bit rates (11 bit data frames are
not supported by Hayes modems at bit rates of greater than 300 bps). The parity bit is optional as odd or even. If it is programmed as odd or even, the data frame consists of 1 start bit, 8 data bits, 1 parity bit, and 1 stop bit.
Modbus protocol can be implemented at any standard communication speed. The 489 RS485 ports support operation at
1200, 2400, 4800, 9600, and 19200 baud. The front panel RS232 baud rate is fixed at 9600 baud.
6.1.4 DATA PACKET FORMAT
A complete request/response sequence consists of the following bytes (transmitted as separate data frames):
1.
A Master Query Message consisting of: a 1-byte Slave Address, a 1-byte Function Code, a variable number of Data
Bytes depending on the Function Code, and a 2-byte CRC code.
2.
A Slave Response Message consisting of: a 1-byte Slave Address, a 1-byte Function Code, a variable number of Data
Bytes depending on the Function Code, and a 2-byte CRC code.
The terms Slave Address, Function Code, Data Bytes, and CRC are explained below:
•
SLAVE ADDRESS: This is the first byte of every transmission. This byte represents the user-assigned address of the
slave device that is to receive the message sent by the master. Each slave device must be assigned a unique address
and only the addressed slave will respond to a transmission that starts with its address. In a master request transmission the Slave Address represents the address of the slave to which the request is being sent. In a slave response
transmission the Slave Address represents the address of the slave that is sending the response. The RS232 port
ignores the slave address, so it will respond regardless of the value in the message. Note: A master transmission with
a Slave Address of 0 indicates a broadcast command. Broadcast commands can be used for specific functions.
•
FUNCTION CODE: This is the second byte of every transmission. Modbus defines function codes of 1 to 127. The 489
implements some of these functions. In a master request transmission the Function Code tells the slave what action to
perform. In a slave response transmission if the Function Code sent from the slave is the same as the Function Code
sent from the master indicating the slave performed the function as requested. If the high order bit of the Function
Code sent from the slave is a 1 (i.e. if the Function Code is greater than 127) then the slave did not perform the function as requested and is sending an error or exception response.
GE Multilin
489 Generator Management Relay
6-1
6
6.1 MODBUS PROTOCOL
6 COMMUNICATIONS
•
DATA BYTES: This is a variable number of bytes depending on the Function Code. These may be actual values, setpoints, or addresses sent by the master to the slave or vice-versa. Data is sent MSByte first followed by the LSByte.
•
CRC: This is a two byte error checking code. CRC is sent LSByte first followed by the MSByte. The RTU version of
Modbus includes a two byte CRC-16 (16-bit cyclic redundancy check) with every transmission. The CRC-16 algorithm
essentially treats the entire data stream (data bits only; start, stop and parity ignored) as one continuous binary number. This number is first shifted left 16 bits and then divided by a characteristic polynomial (11000000000000101B).
The 16-bit remainder of the division is appended to the end of the transmission, LSByte first. The resulting message
including CRC, when divided by the same polynomial at the receiver will give a zero remainder if no transmission
errors have occurred.
If a 489 Modbus slave device receives a transmission in which an error is indicated by the CRC-16 calculation, the slave
device will not respond to the transmission. A CRC-16 error indicates than one or more bytes of the transmission were
received incorrectly and thus the entire transmission should be ignored in order to avoid the 489 performing any incorrect
operation. The CRC-16 calculation is an industry standard method used for error detection. An algorithm is included here to
assist programmers in situations where no standard CRC-16 calculation routines are available.
6.1.5 CRC-16 ALGORITHM
Once the following algorithm is complete, the working register "A" will contain the CRC value to be transmitted. Note that
this algorithm requires the characteristic polynomial to be reverse bit ordered. The MSbit of the characteristic polynomial is
dropped since it does not affect the value of the remainder. The following symbols are used in the algorithm:
Symbols: --> data transfer
A
16 bit working register
low order byte of A
Alow
Ahigh
high order byte of A
CRC
16 bit CRC-16 result
i, j
loop counters
(+)
logical EXCLUSIVE-OR operator
N
total number of data bytes
i-th data byte (i = 0 to N-1)
Di
G
16 bit characteristic polynomial = 1010000000000001 (binary) with MSbit dropped and bit order reversed
shr (x)
right shift operator (the LSbit of x is shifted into a carry flag, a '0' is shifted into the MSbit of x, all other bits
are shifted right one location)
6
Algorithm:
1.
2.
3.
4.
5.
6.
7.
8.
9.
10.
FFFF (hex) --> A
0 --> i
0 --> j
Di (+) Alow --> Alow
j + 1 --> j
shr (A)
Is there a carry? If
If
Is j = 8?
If No: go
i + 1 --> i
Is i = N?
If No: go
11.
A --> CRC
No: go to step 8.
Yes: G (+) A --> A and continue.
to 5.; If Yes: continue.
to 3.; If Yes: continue.
6.1.6 TIMING
Data packet synchronization is maintained by timing constraints. The receiving device must measure the time between the
reception of characters. If three and one half character times elapse without a new character or completion of the packet,
then the communication link must be reset (i.e. all slaves start listening for a new transmission from the master). Thus at
9600 baud a delay of greater than 3.5 × 1 / 9600 × 10 = 3.65 ms will cause the communication link to be reset.
6-2
489 Generator Management Relay
GE Multilin
6 COMMUNICATIONS
6.2 MODBUS FUNCTIONS
6.2MODBUS FUNCTIONS
6.2.1 SUPPORTED FUNCTIONS
The following functions are supported by the 489:
•
Function Code 03: Read Setpoints and Actual Values
•
Function Code 04: Read Setpoints and Actual Values
•
Function Code 05: Execute Operation
•
Function Code 06: Store Single Setpoint
•
Function Code 07: Read Device Status
•
Function Code 08: Loopback Test
•
Function Code 16: Store Multiple Setpoints
A detailed explanation of how the 489 implements these function codes is shown in the following sections.
6.2.2 FUNCTION CODES 03/04: READ SETPOINTS / ACTUAL VALUES
Modbus implementation:
489 Implementation:
Read Input and Holding Registers
Read Setpoints and Actual Values
For the 489 Modbus implementation, these commands are used to read any setpoint ("holding registers") or actual value
("input registers"). Holding and input registers are 16-bit (two byte) values transmitted high order byte first. Thus all 489 setpoints and actual values are sent as two bytes. The maximum of 125 registers can be read in one transmission. Function
codes 03 and 04 are configured to read setpoints or actual values interchangeably since some PLCs do not support both
function codes.
The slave response to these function codes is the slave address, function code, a count of the number of data bytes to follow, the data itself and the CRC. Each data item is sent as a two byte number with the high order byte sent first. The CRC
is sent as a two byte number with the low order byte sent first.
MESSAGE FORMAT AND EXAMPLE
Request slave 11 to respond with 2 registers starting at address 0235. For this example, the register data in these
addresses is:
ADDRESS
DATA
0235
0064
0236
000A
MASTER TRANSMISSION:
BYTES
EXAMPLE (HEX):
SLAVE ADDRESS
1
0B
message for slave 11
FUNCTION CODE
1
03
read registers
DATA STARTING ADDRESS
2
02 35
data starting at 0235
NUMBER OF SETPOINTS
2
00 02
2 registers (4 bytes total)
CRC
2
D5 17
CRC calculated by the master
SLAVE RESPONSE:
BYTES
EXAMPLE (HEX):
SLAVE ADDRESS
1
0B
response message from slave 11
FUNCTION CODE
1
03
read registers
BYTE COUNT
1
04
2 registers = 4 bytes
DATA 1
2
00 64
value in address 0308
DATA 2
2
00 0A
value in address 0309
CRC
2
EB 91
CRC calculated by the slave
GE Multilin
489 Generator Management Relay
6-3
6
6.2 MODBUS FUNCTIONS
6 COMMUNICATIONS
6.2.3 FUNCTION CODE 05: EXECUTE OPERATION
Modbus Implementation:
489 Implementation:
Force Single Coil
Execute Operation
This function code allows the master to request specific 489 command operations. The command numbers listed in the
Commands area of the memory map correspond to operation code for function code 05. The operation commands can also
be initiated by writing to the Commands area of the memory map using function code 16. Refer to Section 6.2.7 Function
Code 16: Store Multiple Setpoints on page 6–6 for complete details.
Supported Operations:
Reset 489 (operation code 1); Generator Start (operation code 2);
Generator Stop (operation code 3); Waveform Trigger (operation code 4)
MESSAGE FORMAT AND EXAMPLE
Reset 489 (operation code 1).
6
MASTER TRANSMISSION:
BYTES
EXAMPLE (HEX):
SLAVE ADDRESS
1
0B
message for slave 11
FUNCTION CODE
1
05
execute operation
OPERATION CODE
2
00 01
reset command (operation code 1)
CODE VALUE
2
FF 00
perform function
CRC
2
DD 50
CRC calculated by the master
SLAVE RESPONSE:
BYTES
EXAMPLE (HEX):
SLAVE ADDRESS
1
0B
response message from slave 11
FUNCTION CODE
1
05
execute operation
reset command (operation code 1)
OPERATION CODE
2
00 01
CODE VALUE
2
FF 00
perform function
CRC
2
DD 50
CRC calculated by the slave
6.2.4 FUNCTION CODE 06: STORE SINGLE SETPOINT
Modbus Implementation:
489 Implementation:
Preset Single Register
Store Single Setpoint
This command allows the master to store a single setpoint into the 489 memory. The slave response to this function code is
to echo the entire master transmission.
MESSAGE FORMAT AND EXAMPLE
Request slave 11 to store the value 01F4 in Setpoint address 1180. After the transmission in this example is complete, Setpoints address 1180 will contain the value 01F4.
MASTER TRANSMISSION:
BYTES
EXAMPLE (HEX):
SLAVE ADDRESS
1
0B
message for slave 11
FUNCTION CODE
1
06
store single setpoint
DATA STARTING ADDRESS
2
11 80
setpoint address 1180
DATA
2
01 F4
data for address 1180
CRC
2
8D A3
CRC calculated by the master
SLAVE RESPONSE:
EXAMPLE (HEX):
SLAVE ADDRESS
1
0B
FUNCTION CODE
1
06
store single setpoint
DATA STARTING ADDRESS
2
11 80
setpoint address 1180
DATA
2
01 F4
data for address 1180
CRC
2
8D A3
CRC calculated by the slave
6-4
message for slave 11
489 Generator Management Relay
GE Multilin
6 COMMUNICATIONS
6.2 MODBUS FUNCTIONS
6.2.5 FUNCTION CODE 07: READ DEVICE STATUS
Modbus Implementation:
489 Implementation:
Read Exception Status
Read Device Status
This function reads the selected device status. A short message length allows for rapid reading of status. The returned status byte has individual bits set to 1 or 0 depending on the slave device status. The 489 general status byte is shown below:
BIT NO.
DESCRIPTION
B0
R1 Trip relay operated = 1
B1
R2 Auxiliary relay operated = 1
B2
R3 Auxiliary relay operated = 1
B3
R4 Auxiliary relay operated = 1
B4
R5 Alarm start relay operated = 1
B5
R6 Service relay operated = 1
B6
Stopped = 1
B7
Running = 1
Note that if status is neither stopped or running, the generator is starting.
MESSAGE FORMAT AND EXAMPLE
Request status from slave 11.
MASTER TRANSMISSION:
BYTES
EXAMPLE (HEX):
SLAVE ADDRESS
1
0B
message for slave 11
FUNCTION CODE
1
07
read device status
CRC
2
47 42
CRC calculated by the master
SLAVE RESPONSE:
BYTES
EXAMPLE (HEX):
SLAVE ADDRESS
1
0B
message for slave 11
FUNCTION CODE
1
07
read device status
DEVICE STATUS
1
59
status = 01011001 in binary
CRC
2
C2 08
CRC calculated by the slave
6
6.2.6 FUNCTION CODE 08: LOOPBACK TEST
Modbus Implementation:
489 Implementation:
Loopback Test
Loopback Test
This function is used to test the integrity of the communication link. The 489 will echo the request.
MESSAGE FORMAT AND EXAMPLE
Loopback test from slave 11.
MASTER TRANSMISSION:
BYTES
EXAMPLE (HEX):
SLAVE ADDRESS
1
0B
FUNCTION CODE
1
08
loopback test
DIAG CODE
2
00 00
must be 00 00
message for slave 11
DATA
2
00 00
must be 00 00
CRC
2
E0 A1
CRC calculated by the master
SLAVE RESPONSE:
BYTES
EXAMPLE (HEX):
SLAVE ADDRESS
1
0B
FUNCTION CODE
1
08
loopback test
DIAG CODE
2
00 00
must be 00 00
message for slave 11
DATA
2
00 00
must be 00 00
CRC
2
E0 A1
CRC calculated by the slave
GE Multilin
489 Generator Management Relay
6-5
6.2 MODBUS FUNCTIONS
6 COMMUNICATIONS
6.2.7 FUNCTION CODE 16: STORE MULTIPLE SETPOINTS
Modbus Implementation:
489 Implementation:
Preset Multiple Registers
Store Multiple Setpoints
This function code allows multiple Setpoints to be stored into the 489 memory. Modbus "registers" are 16-bit (two byte) values transmitted high order byte first. Thus all 489 setpoints are sent as two bytes. The maximum number of Setpoints that
can be stored in one transmission is dependent on the slave device. Modbus allows up to a maximum of 60 holding registers to be stored. The 489 response to this function code is to echo the slave address, function code, starting address, the
number of Setpoints stored, and the CRC.
MESSAGE FORMAT AND EXAMPLE
Request slave 11 to store the value 01F4 to Setpoint address 1180 and the value 0001 to setpoint address 1181. After the
transmission in this example is complete, 489 slave 11 will have the following setpoints information stored:
6
ADDRESS
DATA
1180
01F4
1181
0001
MASTER TRANSMISSION:
BYTES
EXAMPLE (hex):
SLAVE ADDRESS
1
0B
message for slave 11
FUNCTION CODE
1
10
store setpoints
DATA STARTING ADDRESS
2
11 80
data starting at 1180
NUMBER OF SETPOINTS
2
00 02
2 setpoints (4 bytes total)
BYTE COUNT
1
04
2 registers = 4 bytes
DATA 1
2
01 F4
data for address 1180
DATA 2
2
00 01
data for address 1181
CRC
2
9B 89
CRC calculated by the master
SLAVE RESPONSE:
BYTES
EXAMPLE (hex):
SLAVE ADDRESS
1
0B
response message from slave 11
store setpoints
FUNCTION CODE
1
10
DATA STARTING ADDRESS
2
11 80
data starting at 1180
NUMBER OF SETPOINTS
2
00 02
2 setpoints (4 bytes total)
CRC
2
45 B6
CRC calculated by the slave
6-6
489 Generator Management Relay
GE Multilin
6 COMMUNICATIONS
6.2 MODBUS FUNCTIONS
6.2.8 FUNCTION CODE 16: PERFORMING COMMANDS
Some PLCs may not support execution of commands using function code 5 but do support storing multiple setpoints using
function code 16. To perform this operation using function code 16 (10H), a certain sequence of commands must be written
at the same time to the 489. The sequence consists of: Command Function register, Command operation register and
Command Data (if required). The Command Function register must be written with the value of 5 indicating an execute
operation is requested. The Command Operation register must then be written with a valid command operation number
from the list of commands shown in the memory map. The Command Data registers must be written with valid data if the
command operation requires data. The selected command will execute immediately upon receipt of a valid transmission.
MESSAGE FORMAT AND EXAMPLE
Perform a 489 RESET (operation code 1).
MASTER TRANSMISSION:
BYTES
EXAMPLE (HEX):
SLAVE ADDRESS
1
0B
message for slave 11
FUNCTION CODE
1
10
store setpoints
DATA STARTING ADDRESS
2
00 80
setpoint address 0080
NUMBER OF SETPOINTS
2
00 02
2 setpoints (4 bytes total)
BYTE COUNT
1
04
2 registers = 4 bytes
COMMAND FUNCTION
2
00 05
data for address 0080
COMMAND FUNCTION
2
00 01
data for address 0081
CRC
2
0B D6
CRC calculated by the master
SLAVE RESPONSE:
BYTES
EXAMPLE (HEX):
SLAVE ADDRESS
1
0B
FUNCTION CODE
1
10
store setpoints
DATA STARTING ADDRESS
2
00 80
setpoint address 0080
NUMBER OF SETPOINTS
2
00 02
2 setpoints (4 bytes total)
CRC
2
40 8A
CRC calculated by the slave
response message from slave 11
6.2.9 ERROR RESPONSES
When a 489 detects an error other than a CRC error, a response will be sent to the master. The MSbit of the Function Code
byte will be set to 1 (i.e. the function code sent from the slave will be equal to the function code sent from the master plus
128). The following byte will be an exception code indicating the type of error that occurred.
Transmissions received from the master with CRC errors will be ignored by the 489.
The slave response to an error (other than CRC error) will be:
•
SLAVE ADDRESS: 1 byte
•
FUNCTION CODE: 1 byte (with MSbit set to 1)
•
EXCEPTION CODE: 1 byte
•
CRC: 2 bytes
The 489 implements the following exception response codes.
01: ILLEGAL FUNCTION
The function code transmitted is not one of the functions supported by the 489.
02: ILLEGAL DATA ADDRESS
The address referenced in the data field transmitted by the master is not an allowable address for the 489.
03: ILLEGAL DATA VALUE
The value referenced in the data field transmitted by the master is not within range for the selected data address.
GE Multilin
489 Generator Management Relay
6-7
6
6.3 MODBUS MEMORY MAP
6 COMMUNICATIONS
6.3MODBUS MEMORY MAP
6.3.1 MEMORY MAP INFORMATION
The data stored in the 489 is grouped as Setpoints and Actual Values. Setpoints can be read and written by a master computer. Actual Values are read only. All Setpoints and Actual Values are stored as two byte values. That is, each register
address is the address of a two-byte value. Addresses are listed in hexadecimal. Data values (Setpoint ranges, increments,
and factory values) are in decimal.
NOTE
Many Modbus communications drivers add 40001d to the actual address of the register addresses. For example: if
address 0h was to be read, 40001d would be the address required by the Modbus communications driver; if
address 320h (800d) was to be read, 40801d would be the address required by the Modbus communications driver.
6.3.2 USER-DEFINABLE MEMORY MAP AREA
The 489 contains a User Definable area in the memory map. This area allows remapping of the addresses of all Actual Values and Setpoints registers. The User Definable area has two sections:
1.
A Register Index area (memory map addresses 0180h to 01FCh) that contains 125 Actual Values or Setpoints register
addresses.
2.
A Register area (memory map addresses 0100h to 017Ch) that contains the data at the addresses in the Register
Index.
Register data that is separated in the rest of the memory map may be remapped to adjacent register addresses in the User
Definable Registers area. This is accomplished by writing to register addresses in the User Definable Register Index area.
This allows for improved throughput of data and can eliminate the need for multiple read command sequences.
For example, if the values of Average Phase Current (register addresses 0412h and 0413h) and Hottest Stator RTD Temperature (register address 04A0h) are required to be read from an 489, their addresses may be remapped as follows:
6
1.
Write 0412h to address 0180h (User Definable Register Index 0000) using function code 06 or 16.
2.
Write 0413h to address 0181h (User Definable Register Index 0001) using function code 06 or 16.
(Average Phase Current is a double register number)
3.
Write 04A0h to address 0182h (User Definable Register Index 0001) using function code 06 or 16.
A read (function code 03 or 04) of registers 0100h (User Definable Register 0000) and 0101h (User Definable Register
0001) will return the Average Phase Current and register 0102h (User Definable Register 0002) will return the Hottest Stator RTD Temperature.
6.3.3 EVENT RECORDER
The 489 event recorder data starts at address 3000h. Address 3003h is the ID number of the event of interest (a high number representing the latest event and a low number representing the oldest event). Event numbers start at zero each time
the event record is cleared, and count upwards. To retrieve event 1, write ‘1’ to the Event Record Selector (3003h) and read
the data from 3004h to 30E7h. To retrieve event 2, write ‘2’ to the Event Record Selector (3003h) and read the data from
3004h to 30E7h. All 40 events may be retrieved in this manner. The time and date stamp of each event may be used to
ensure that all events have been retrieved in order without new events corrupting the sequence of events (event 0 should
be less recent than event 1, event 1 should be less recent than event 2, etc.).
If more than 40 events have been recorded since the last time the event record was cleared, the earliest events will not be
accessible. For example, if 100 events have been recorded (i.e., the total events since last clear in register 3002h is 100),
events 60 through 99 may be retrieved. Writing any other value to the event record selector (register 3003h) will result in an
“invalid data value” error.
Each communications port can individually select the ID number of the event of interest by writing address 3003h. This way
the front port, rear port and auxiliary port can read different events from the event recorder simultaneously.
6-8
489 Generator Management Relay
GE Multilin
6 COMMUNICATIONS
6.3 MODBUS MEMORY MAP
6.3.4 WAVEFORM CAPTURE
The 489 stores up to 64 cycles of A/D samples in a waveform capture buffer each time a trip occurs. The waveform capture
buffer is time and date stamped and may therefore be correlated to a trip in the event record. To access the waveform capture memory, select the channel of interest by writing the number to the Waveform Capture Channel Selector (30F5h).
Then read the waveform capture data from address 3100h-31BFh, and read the date, time and line frequency from
addresses 30F0h-30F4h.
Each communications port can individually select a Waveform Channel Selector of interest by writing address 30F5h. This
way the front port, rear port and auxiliary port can read different Waveform Channels simultaneously.
The channel selector must be one of the following values:
VALUE
SELECTED A/D SAMPLES
SCALE FACTOR
0
Phase A line current
500 counts equals 1 × CT primary
1
Phase B line current
500 counts equals 1 × CT primary
2
Phase C line current
500 counts equals 1 × CT primary
3
Neutral-End phase A current
500 counts equals 1 × CT primary
4
Neutral-End phase B current
500 counts equals 1 × CT primary
5
Neutral-End phase C current
500 counts equals 1 × CT primary
6
Ground current
500 counts equals 1 × CT primary or 1A for 50:0.025
7
Phase A to neutral voltage
2500 counts equals 120 secondary volts
8
Phase B to neutral voltage
2500 counts equals 120 secondary volts
9
Phase C to neutral voltage
2500 counts equals 120 secondary volts
6.3.5 DUAL SETPOINTS
Each communications port can individually select an Edit Setpoint Group of interest by writing address 1342h. This way the
front port, rear port and auxiliary port can read and alter different setpoints simultaneously.
6.3.6 PASSCODE OPERATION
Each communications port can individually set the Passcode Access by writing address 88h with the correct Passcode.
This way the front port, rear port and auxiliary port have individual access to the setpoints. Reading address 0203h, COMMUNICATIONS SETPOINT ACCESS register, provides the user with the current state of access for the given port. A value
of 1 read from this register indicates that the user has full access rights to changing setpoints from the given port.
GE Multilin
489 Generator Management Relay
6-9
6
6.3 MODBUS MEMORY MAP
6 COMMUNICATIONS
6.3.7 489 MEMORY MAP
Table 6–1: 489 MEMORY MAP (SHEET 1 OF 24)
6
ADDR NAME
PRODUCT ID
0000 GE MULTILIN PRODUCT DEVICE CODE
0001 PRODUCT HARDWARE REVISION
0002 PRODUCT SOFTWARE REVISION
0003 PRODUCT MODIFICATION NUMBER
0010 BOOT PROGRAM REVISION
0011 BOOT PROGRAM MODIFICATION NUMBER
MODEL ID
0040 ORDER CODE
0050 489 REVISION
0060 489 BOOT REVISION
COMMANDS
0080 COMMAND FUNCTION CODE (always 5)
0081 COMMAND OPERATION CODE
0088 COMMUNICATIONS PORT PASSCODE
00F0 TIME (BROADCAST)
00F2 DATE (BROADCAST)
USER_MAP / USER MAP VALUES
0100 USER MAP VALUE #1 of 125...
017C USER MAP VALUE #125 of 125
USER_MAP / USER MAP ADDRESSES
0180 USER MAP ADDRESS #1 of 125...
01FC USER MAP ADDRESS #125 of 125
STATUS / GENERATOR STATUS
0200 GENERATOR STATUS
0201 GENERATOR THERMAL CAPACITY USED
0202 ESTIMATED TRIP TIME ON OVERLOAD
0203 COMMUNICATIONS SETPOINT ACCESS
STATUS / SYSTEM STATUS
0210 GENERAL STATUS
0211 OUTPUT RELAY STATUS
0212 ACTIVE SETPOINT GROUP
STATUS / LAST TRIP DATA
0220 CAUSE OF LAST TRIP
0221 TIME OF LAST TRIP
0223 DATE OF LAST TRIP
0225 TACHOMETER PreTrip
0226 PHASE A PRE-TRIP CURRENT
0228 PHASE B PRE-TRIP CURRENT
022A PHASE C PRE-TRIP CURRENT
022C PHASE A PRE-TRIP DIFFERENTIAL CURRENT
022E PHASE B PRE-TRIP DIFFERENTIAL CURRENT
0230 PHASE C PRE-TRIP DIFFERENTIAL CURRENT
0232 NEG. SEQ. CURRENT PreTrip
0233 GROUND CURRENT PreTrip
0235 PRE-TRIP A-B VOLTAGE
0236 PRE-TRIP B-C VOLTAGE
0237 PRE-TRIP C-A VOLTAGE
0238 FREQUENCY Pretrip
023B REAL POWER (MW) PreTrip
023D REACTIVE POWER Mvar PreTrip
023F APPARENT POWER MVA PreTrip
0241 LAST TRIP DATA STATOR RTD
0242 HOTTEST STATOR RTD TEMPERATURE
0243 LAST TRIP DATA BEARING RTD
0244 HOTTEST BEARING RTD TEMPERATURE
0245 LAST TRIP DATA OTHER RTD
0246 HOTTEST OTHER RTD TEMPERATURE
0247 LAST TRIP DATA AMBIENT RTD
0248 HOTTEST AMBIENT RTD TEMPERATURE
0249 ANALOG IN 1 PreTrip
024B ANALOG IN 2 PreTrip
024D ANALOG IN 3 PreTrip
024F ANALOG IN 4 PreTrip
1, 2, 3
See Table footnotes on page 6–33
6-10
RANGE
STEP
UNITS
FORMAT
DEFAULT
N/A
1 to 26
N/A
0 to 999
N/A
0 to 999
N/A
1
N/A
1
N/A
1
N/A
N/A
N/A
N/A
N/A
N/A
F1
F15
F16
F1
F16
F1
32
N/A
N/A
N/A
N/A
N/A
0 to 16
12
12
1
1
1
N/A
N/A
N/A
F22
F22
F22
N/A
N/A
N/A
5
0 to 65535
0 to 99999999
N/A
N/A
N/A
1
1
N/A
N/A
N/A
N/A
N/A
N/A
N/A
F1
F1
F12
F24
F18
N/A
N/A
0
N/A
N/A
5
5
N/A
N/A
N/A
N/A
F1
F1
N/A
N/A
0 to 3FFF
0 to 3FFF
1
1
hex
hex
F1
F1
0
0
0 to 4
0 to 100
0 to 65535 1
0 to 1
1
1
1
N/A
–
%
s
N/A
F133
F1
F12
F126
1
0
–1
N/A
0 to 65535
0 to 63
0 to 1
1
1
1
N/A
N/A
N/A
F140
F141
F118
0
0
0
0 to 139
N/A
N/A
0 to 7200
0 to 999999
0 to 999999
0 to 999999
0 to 999999
0 to 999999
0 to 999999
0 to 2000
0 to 20000000
0 to 50000
0 to 50000
0 to 50000
0 to 12000
–2000000 to 2000000
–2000000 to 2000000
0 to 2000000
1 to 12
–50 to 250
1 to 12
–50 to 250
1 to 12
–50 to 250
1 to 12
–50 to 250
–50000 to 50000
–50000 to 50000
–50000 to 50000
–50000 to 50000
1
N/A
N/A
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
–
N/A
N/A
RPM
Amps
Amps
Amps
Amps
Amps
Amps
% FLA
A
Volts
Volts
Volts
Hz
MW
Mvar
MVA
–
°C
–
°C
–
°C
–
°C
Units
Units
Units
Units
F134
F19
F18
F1
F12
F12
F12
F12
F12
F12
F1
F14
F1
F1
F1
F3
F13
F13
F13
F1
F4
F1
F4
F1
F4
F1
F4
F12
F12
F12
F12
0
N/A
N/A
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
0
1
0
1
0
1
0
0
0
0
0
489 Generator Management Relay
GE Multilin
6 COMMUNICATIONS
6.3 MODBUS MEMORY MAP
Table 6–1: 489 MEMORY MAP (SHEET 2 OF 24)
ADDR NAME
025C HOTTEST STATOR RTD TEMPERATURE
025D HOTTEST BEARING RTD TEMPERATURE
025E HOTTEST OTHER RTD TEMPERATURE
025F HOTTEST AMBIENT RTD TEMPERATURE
0260 NEUTRAL VOLT FUND PreTrip
0262 NEUTRAL VOLT 3rd PreTrip
0264 PRE-TRIP Vab/Iab
0265 PRE-TRIP Vab/Iab ANGLE
STATUS / TRIP PICKUPS
0280 INPUT A PICKUP
0281 INPUT B PICKUP
0282 INPUT C PICKUP
0283 INPUT D PICKUP
0284 INPUT E PICKUP
0285 INPUT F PICKUP
0286 INPUT G PICKUP
0287 SEQUENTIAL TRIP PICKUP
0288 FIELD-BKR DISCREP. PICKUP
0289 TACHOMETER PICKUP
028A OFFLINE OVERCURRENT PICKUP
028B INADVERTENT ENERG. PICKUP
028C PHASE OVERCURRENT PICKUP
028D NEG.SEQ. OVERCURRENT PICKUP
028E GROUND OVERCURRENT PICKUP
028F PHASE DIFFERENTIAL PICKUP
0290 UNDERVOLTAGE PICKUP
0291 OVERVOLTAGE PICKUP
0292 VOLTS/HERTZ PICKUP
0293 PHASE REVERSAL PICKUP
0294 UNDERFREQUENCY PICKUP
0295 OVERFREQUENCY PICKUP
0296 NEUTRAL O/V (FUND) PICKUP
0297 NEUTRAL U/V (3rd) PICKUP
0298 REACTIVE POWER PICKUP
0299 REVERSE POWER PICKUP
029A LOW FORWARD POWER PICKUP
029B THERMAL MODEL PICKUP
029C RTD #1 PICKUP
029D RTD #2 PICKUP
029E RTD #3 PICKUP
029F RTD #4 PICKUP
02A0 RTD #5 PICKUP
02A1 RTD #6 PICKUP
02A2 RTD #7 PICKUP
02A3 RTD #8 PICKUP
02A4 RTD #9 PICKUP
02A5 RTD #10 PICKUP
02A6 RTD #11 PICKUP
02A7 RTD #12 PICKUP
02A8 Analog I/P 1 PICKUP
02A9 Analog I/P 2 PICKUP
02AA Analog I/P 3 PICKUP
02AB Analog I/P 4 PICKUP
02AC LOSS OF EXCITATION 1 PICKUP
02AD LOSS OF EXCITATION 2 PICKUP
02AE GROUND DIRECTIONAL PICKUP
02AF HIGH-SET PHASE O/C PICKUP
02B0 DISTANCE ZONE 1 PICKUP
02B1 DISTANCE ZONE 2 PICKUP
STATUS / ALARM PICKUPS
0300 INPUT A PICKUP
0301 INPUT B PICKUP
0302 INPUT C PICKUP
0303 INPUT D PICKUP
0304 INPUT E PICKUP
0305 INPUT F PICKUP
1, 2, 3
See Table footnotes on page 6–33
GE Multilin
RANGE
–50 to 250
–50 to 250
–50 to 250
–50 to 250
0 to 250000
0 to 250000
0 to 65535
0 to 359
STEP
1
1
1
1
1
1
1
1
UNITS
°F
°F
°F
°F
Volts
Volts
ohms s
°
FORMAT
F4
F4
F4
F4
F10
F10
F2
F1
DEFAULT
0
0
0
0
0
0
0
0
0 to 4
0 to 4
0 to 4
0 to 4
0 to 4
0 to 4
0 to 4
0 to 4
0 to 4
0 to 4
0 to 4
0 to 4
0 to 4
0 to 4
0 to 4
0 to 4
0 to 4
0 to 4
0 to 4
0 to 4
0 to 4
0 to 4
0 to 4
0 to 4
0 to 4
0 to 4
0 to 4
0 to 4
0 to 4
0 to 4
0 to 4
0 to 4
0 to 4
0 to 4
0 to 4
0 to 4
0 to 4
0 to 4
0 to 4
0 to 4
0 to 4
0 to 4
0 to 4
0 to 4
0 to 4
0 to 4
0 to 4
0 to 4
0 to 4
0 to 4
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
F123
F123
F123
F123
F123
F123
F123
F123
F123
F123
F123
F123
F123
F123
F123
F123
F123
F123
F123
F123
F123
F123
F123
F123
F123
F123
F123
F123
F123
F123
F123
F123
F123
F123
F123
F123
F123
F123
F123
F123
F123
F123
F123
F123
F123
F123
F123
F123
F123
F123
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0 to 4
0 to 4
0 to 4
0 to 4
0 to 4
0 to 4
1
1
1
1
1
1
–
–
–
–
–
–
F123
F123
F123
F123
F123
F123
0
0
0
0
0
0
489 Generator Management Relay
6
6-11
6.3 MODBUS MEMORY MAP
6 COMMUNICATIONS
Table 6–1: 489 MEMORY MAP (SHEET 3 OF 24)
6
ADDR NAME
0306 INPUT G PICKUP
0307 TACHOMETER PICKUP
0308 OVERCURRENT PICKUP
0309 NEG SEQ OVERCURRENT PICKUP
030A GROUND OVERCURRENT PICKUP
030B UNDERVOLTAGE PICKUP
030C OVERVOLTAGE PICKUP
030D VOLTS/HERTZ PICKUP
030E UNDERFREQUENCY PICKUP
030F OVERFREQUENCY PICKUP
0310 NEUTRAL O/V (FUND) PICKUP
0311 NEUTRAL U/V (3rd) PICKUP
0312 REACTIVE POWER PICKUP
0313 REVERSE POWER PICKUP
0314 LOW FORWARD POWER PICKUP
0315 RTD #1 PICKUP
0316 RTD #2 PICKUP
0317 RTD #3 PICKUP
0318 RTD #4 PICKUP
0319 RTD #5 PICKUP
031A RTD #6 PICKUP
031B RTD #7 PICKUP
031C RTD #8 PICKUP
031D RTD #9 PICKUP
031E RTD #10 PICKUP
031F RTD #11 PICKUP
0320 RTD #12 PICKUP
0321 OPEN SENSOR PICKUP
0322 SHORT/LOW TEMP PICKUP
0323 THERMAL MODEL PICKUP
0324 TRIP COUNTER PICKUP
0325 BREAKER FAILURE PICKUP
0326 TRIP COIL MONITOR PICKUP
0327 VT FUSE FAILURE PICKUP
0328 CURRENT DEMAND PICKUP
0329 MW DEMAND PICKUP
032A Mvar DEMAND PICKUP
032B MVA DEMAND PICKUP
032C ANALOG INPUT 1 PICKUP
032D ANALOG INPUT 2 PICKUP
032E ANALOG INPUT 3 PICKUP
032F ANALOG INPUT 4 PICKUP
0330 NOT PROGRAMMED PICKUP
0331 SIMULATION MODE PICKUP
0332 OUTPUT RELAYS FORCED PICKUP
0333 ANALOG OUTPUT FORCED PICKUP
0334 TEST SWITCH SHORTED PICKUP
0335 GROUND DIRECTIONAL PICKUP
0336 IRIG-B ALARM PICKUP
0337 GENERATOR RUNNING HOUR PICKUP
STATUS / DIGITAL INPUTS
0380 ACCESS SWITCH STATE
0381 BREAKER STATUS SWITCH STATE
0382 ASSIGNABLE DIGITAL INPUT1 STATE
0383 ASSIGNABLE DIGITAL INPUT2 STATE
0384 ASSIGNABLE DIGITAL INPUT3 STATE
0385 ASSIGNABLE DIGITAL INPUT4 STATE
0386 ASSIGNABLE DIGITAL INPUT5 STATE
0387 ASSIGNABLE DIGITAL INPUT6 STATE
0388 ASSIGNABLE DIGITAL INPUT7 STATE
0389 TRIP COIL SUPERVISION
STATUS / REAL TIME CLOCK
03FC DATE (READ-ONLY)
03FE TIME (READ-ONLY)
METERING DATA / CURRENT METERING
0400 PHASE A OUTPUT CURRENT
1, 2, 3
See Table footnotes on page 6–33
6-12
RANGE
0 to 4
0 to 4
0 to 4
0 to 4
0 to 4
0 to 4
0 to 4
0 to 4
0 to 4
0 to 4
0 to 4
0 to 4
0 to 4
0 to 4
0 to 4
0 to 4
0 to 4
0 to 4
0 to 4
0 to 4
0 to 4
0 to 4
0 to 4
0 to 4
0 to 4
0 to 4
0 to 4
0 to 4
0 to 4
0 to 4
0 to 4
0 to 4
0 to 4
0 to 4
0 to 4
0 to 4
0 to 4
0 to 4
0 to 4
0 to 4
0 to 4
0 to 4
0 to 4
0 to 4
0 to 4
0 to 4
0 to 4
0 to 4
0 to 4
0 to 4
STEP
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
UNITS
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
FORMAT
F123
F123
F123
F123
F123
F123
F123
F123
F123
F123
F123
F123
F123
F123
F123
F123
F123
F123
F123
F123
F123
F123
F123
F123
F123
F123
F123
F123
F123
F123
F123
F123
F123
F123
F123
F123
F123
F123
F123
F123
F123
F123
F123
F123
F123
F123
F123
F123
F123
F123
DEFAULT
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0 to 1
0 to 1
0 to 1
0 to 1
0 to 1
0 to 1
0 to 1
0 to 1
0 to 1
0 to 1
1
1
1
1
1
1
1
1
1
1
–
–
–
–
–
–
–
–
–
–
F207
F207
F207
F207
F207
F207
F207
F207
F207
F132
0
0
0
0
0
0
0
0
0
0
N/A
N/A
N/A
N/A
N/A
N/A
F18
F19
N/A
N/A
0 to 999999
1
Amps
F12
0
489 Generator Management Relay
GE Multilin
6 COMMUNICATIONS
6.3 MODBUS MEMORY MAP
Table 6–1: 489 MEMORY MAP (SHEET 4 OF 24)
ADDR NAME
0402 PHASE B OUTPUT CURRENT
0404 PHASE C OUTPUT CURRENT
0406 PHASE A NEUTRAL-SIDE CURRENT
0408 PHASE B NEUTRAL-SIDE CURRENT
040A PHASE C NEUTRAL-SIDE CURRENT
040C PHASE A DIFFERENTIAL CURRENT
040E PHASE B DIFFERENTIAL CURRENT
0410 PHASE C DIFFERENTIAL CURRENT
0412 AVERAGE PHASE CURRENT
0414 GENERATOR LOAD
0415 NEGATIVE SEQUENCE CURRENT
0416 GROUND CURRENT
0420 PHASE A CURRENT ANGLE
0421 PHASE B CURRENT ANGLE
0422 PHASE C CURRENT ANGLE
0423 PHASE A NEUTRAL-SIDE ANGLE
0424 PHASE B NEUTRAL-SIDE ANGLE
0425 PHASE C NEUTRAL-SIDE ANGLE
0426 PHASE A DIFFERENTIAL ANGLE
0427 PHASE B DIFFERENTIAL ANGLE
0428 PHASE C DIFFERENTIAL ANGLE
0429 GROUND CURRENT ANGLE
METERING DATA / VOLTAGE METERING
0440 PHASE A-B VOLTAGE
0441 PHASE B-C VOLTAGE
0442 PHASE C-A VOLTAGE
0443 AVERAGE LINE VOLTAGE
0444 PHASE A-N VOLTAGE
0445 PHASE B-N VOLTAGE
0446 PHASE C-N VOLTAGE
0447 AVERAGE PHASE VOLTAGE
0448 PER UNIT MEASUREMENT OF V/Hz 2
0449 FREQUENCY
044A NEUTRAL VOLTAGE FUND
044C NEUTRAL VOLTAGE 3rd HARM
044E NEUTRAL VOLTAGE Vp3 3rd HARM
0450 Vab/Iab
0451 Vab/Iab ANGLE
0460 LINE A-B VOLTAGE ANGLE
0461 LINE B-C VOLTAGE ANGLE
0462 LINE C-A VOLTAGE ANGLE
0463 PHASE A-N VOLTAGE ANGLE
0464 PHASE B-N VOLTAGE ANGLE
0465 PHASE C-N VOLTAGE ANGLE
0466 NEUTRAL VOLTAGE ANGLE
METERING DATA / POWER METERING
0480 POWER FACTOR
0481 REAL POWER
0483 REACTIVE POWER
0485 APPARENT POWER
0487 POSITIVE WATTHOURS
0489 POSITIVE VARHOURS
048B NEGATIVE VARHOURS
METERING DATA / TEMPERATURE
04A0 HOTTEST STATOR RTD
04A1 HOTTEST STATOR RTD TEMPERATURE
04A2 RTD #1 TEMPERATURE
04A3 RTD #2 TEMPERATURE
04A4 RTD #3 TEMPERATURE
04A5 RTD #4 TEMPERATURE
04A6 RTD #5 TEMPERATURE
04A7 RTD #6 TEMPERATURE
04A8 RTD #7 TEMPERATURE
04A9 RTD #8 TEMPERATURE
04AA RTD #9 TEMPERATURE
04AB RTD #10 TEMPERATURE
1, 2, 3
See Table footnotes on page 6–33
GE Multilin
RANGE
0 to 999999
0 to 999999
0 to 999999
0 to 999999
0 to 999999
0 to 999999
0 to 999999
0 to 999999
0 to 999999
0 to 2000
0 to 2000
0 to 10000
0 to 359
0 to 359
0 to 359
0 to 359
0 to 359
0 to 359
0 to 359
0 to 359
0 to 359
0 to 359
STEP
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
UNITS
Amps
Amps
Amps
Amps
Amps
Amps
Amps
Amps
Amps
% FLA
% FLA
Amps
°
°
°
°
°
°
°
°
°
°
FORMAT
F12
F12
F12
F12
F12
F12
F12
F12
F12
F1
F1
F14
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
DEFAULT
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0 to 50000
0 to 50000
0 to 50000
0 to 50000
0 to 50000
0 to 50000
0 to 50000
0 to 50000
0 to 200
500 to 9000
0 to 250000
0 to 250000
0 to 250000
0 to 65535
0 to 359
0 to 359
0 to 359
0 to 359
0 to 359
0 to 359
0 to 359
0 to 359
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Volts
Volts
Volts
Volts
Volts
Volts
Volts
Volts
–
Hz
Volts
Volts
Volts
ohms
°
°
°
°
°
°
°
–
F1
F1
F1
F1
F1
F1
F1
F1
F3
F3
F10
F10
F10
F2
F1
F1
F1
F1
F1
F1
F1
F1
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
–100 to 100
–2000000 to 2000000
–2000000 to 2000000
–2000000 to 200000
0 to 4000000000
0 to 4000000000
0 to 4000000000
1
1
1
1
1
1
1
–
MW
Mvar
MVA
MWh
Mvarh
Mvarh
F6
F13
F13
F13
F13
F13
F13
0
0
0
0
0
0
0
1 to 12
–52 to 250
–52 to 251
–52 to 251
–52 to 251
–52 to 251
–52 to 251
–52 to 251
–52 to 251
–52 to 251
–52 to 251
–52 to 251
1
1
1
1
1
1
1
1
1
1
1
1
–
°C
°C
°C
°C
°C
°C
°C
°C
°C
°C
°C
F1
F4
F4
F4
F4
F4
F4
F4
F4
F4
F4
F4
0
–52
–52
–52
–52
–52
–52
–52
–52
–52
–52
–52
489 Generator Management Relay
6
6-13
6.3 MODBUS MEMORY MAP
6 COMMUNICATIONS
Table 6–1: 489 MEMORY MAP (SHEET 5 OF 24)
6
ADDR NAME
04AC RTD #11 TEMPERATURE
04AD RTD #12 TEMPERATURE
04C0 HOTTEST STATOR RTD TEMPERATURE
04C1 RTD #1 TEMPERATURE
04C2 RTD #2 TEMPERATURE
04C3 RTD #3 TEMPERATURE
04C4 RTD #4 TEMPERATURE
04C5 RTD #5 TEMPERATURE
04C6 RTD #6 TEMPERATURE
04C7 RTD #7 TEMPERATURE
04C8 RTD #8 TEMPERATURE
04C9 RTD #9 TEMPERATURE
04CA RTD #10 TEMPERATURE
04CB RTD #11 TEMPERATURE
04CC RTD #12 TEMPERATURE
METERING DATA / DEMAND METERING
04E0 CURRENT DEMAND
04E2 MW DEMAND
04E4 Mvar DEMAND
04E6 MVA DEMAND
04E8 PEAK CURRENT DEMAND
04EA PEAK MW DEMAND
04EC PEAK Mvar DEMAND
04EE PEAK MVA DEMAND
METERING DATA / ANALOG INPUTS
0500 ANALOG INPUT 1
0502 ANALOG INPUT 2
0504 ANALOG INPUT 3
0506 ANALOG INPUT 4
METERING DATA / SPEED
0520 TACHOMETER
LEARNED DATA / PARAMETER AVERAGES
0600 AVERAGE GENERATOR LOAD
0601 AVERAGE NEG. SEQ. CURRENT
0602 AVERAGE PHASE-PHASE VOLTAGE
0603 RESERVED
0604 RESERVED
LEARNED DATA / RTD MAXIMUMS
0620 RTD #1 MAX. TEMP.
0621 RTD #2 MAX. TEMP.
0622 RTD #3 MAX. TEMP.
0623 RTD #4 MAX. TEMP.
0624 RTD #5 MAX. TEMP.
0625 RTD #6 MAX. TEMP.
0626 RTD #7 MAX. TEMP.
0627 RTD #8 MAX. TEMP.
0628 RTD #9 MAX. TEMP.
0629 RTD #10 MAX. TEMP.
062A RTD #11 MAX. TEMP.
062B RTD #12 MAX. TEMP.
0640 RTD #1 MAX. TEMP.
0641 RTD #2 MAX. TEMP.
0642 RTD #3 MAX. TEMP.
0643 RTD #4 MAX. TEMP.
0644 RTD #5 MAX. TEMP.
0645 RTD #6 MAX. TEMP.
0646 RTD #7 MAX. TEMP.
0647 RTD #8 MAX. TEMP.
0648 RTD #9 MAX. TEMP.
0649 RTD #10 MAX. TEMP.
064A RTD #11 MAX. TEMP.
064B RTD #12 MAX. TEMP.
LEARNED DATA / ANALOG IN MIN/MAX
0700 ANALOG INPUT 1 MINIMUM
0702 ANALOG INPUT 1 MAXIMUM
0704 ANALOG INPUT 2 MINIMUM
1, 2, 3
See Table footnotes on page 6–33
6-14
RANGE
–52 to 251
–52 to 251
–52 to 250
–52 to 251
–52 to 251
–52 to 251
–52 to 251
–52 to 251
–52 to 251
–52 to 251
–52 to 251
–52 to 251
–52 to 251
–52 to 251
–52 to 251
STEP
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
UNITS
°C
°C
°F
°F
°F
°F
°F
°F
°F
°F
°F
°F
°F
°F
°F
FORMAT
F4
F4
F4
F4
F4
F4
F4
F4
F4
F4
F4
F4
F4
F4
F4
DEFAULT
–52
–52
–52
–52
–52
–52
–52
–52
–52
–52
–52
–52
–52
–52
–52
0 to 1000000
0 to 2000000
0 to 2000000
0 to 2000000
0 to 1000000
0 to 2000000
0 to 2000000
0 to 2000000
1
1
1
1
1
1
1
1
Amps
MW
Mvar
MVA
Amps
MW
Mvar
MVA
F12
F13
F13
F13
F12
F13
F13
F13
0
0
0
0
0
0
0
0
–50000 to 50000
–50000 to 50000
–50000 to 50000
–50000 to 50000
1
1
1
1
Units
Units
Units
Units
F12
F12
F12
F12
0
0
0
0
0 to 7200
1
RPM
F1
0
0 to 2000
0 to 2000
0 to 50000
–
–
1
1
1
–
–
%FLA
%FLA
V
–
–
F1
F1
F1
–
–
0
0
0
–
–
–52 to 251
–52 to 251
–52 to 251
–52 to 251
–52 to 251
–52 to 251
–52 to 251
–52 to 251
–52 to 251
–52 to 251
–52 to 251
–52 to 251
–52 to 251
–52 to 251
–52 to 251
–52 to 251
–52 to 251
–52 to 251
–52 to 251
–52 to 251
–52 to 251
–52 to 251
–52 to 251
–52 to 251
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
°C
°C
°C
°C
°C
°C
°C
°C
°C
°C
°C
°C
°F
°F
°F
°F
°F
°F
°F
°F
°F
°F
°F
°F
F4
F4
F4
F4
F4
F4
F4
F4
F4
F4
F4
F4
F4
F4
F4
F4
F4
F4
F4
F4
F4
F4
F4
F4
–52
–52
–52
–52
–52
–52
–52
–52
–52
–52
–52
–52
–52
–52
–52
–52
–52
–52
–52
–52
–52
–52
–52
–52
–50000 to 50000
–50000 to 50000
–50000 to 50000
1
1
1
Units
Units
Units
F12
F12
F12
0
0
0
489 Generator Management Relay
GE Multilin
6 COMMUNICATIONS
6.3 MODBUS MEMORY MAP
Table 6–1: 489 MEMORY MAP (SHEET 6 OF 24)
ADDR NAME
0706 ANALOG INPUT 2 MAXIMUM
0708 ANALOG INPUT 3 MINIMUM
070A ANALOG INPUT 3 MAXIMUM
070C ANALOG INPUT 4 MINIMUM
070E ANALOG INPUT 4 MAXIMUM
MAINTENANCE / TRIP COUNTERS
077F TRIP COUNTERS LAST CLEARED (DATE)
0781 TOTAL NUMBER OF TRIPS
0782 DIGITAL INPUT TRIPS
0783 SEQUENTIAL TRIPS
0784 FIELD-BKR DISCREP. TRIPS
0785 TACHOMETER TRIPS
0786 OFFLINE OVERCURRENT TRIPS
0787 PHASE OVERCURRENT TRIPS
0788 NEG.SEQ. OVERCURRENT TRIPS
0789 GROUND OVERCURRENT TRIPS
078A PHASE DIFFERENTIAL TRIPS
078B UNDERVOLTAGE TRIPS
078C OVERVOLTAGE TRIPS
078D VOLTS/HERTZ TRIPS
078E PHASE REVERSAL TRIPS
078F UNDERFREQUENCY TRIPS
0790 OVERFREQUENCY TRIPS
0791 NEUTRAL O/V (FUND) TRIPS
0792 NEUTRAL U/V (3rd) TRIPS
0793 REACTIVE POWER TRIPS
0794 REVERSE POWER TRIPS
0795 LOW FORWARD POWER TRIPS
0796 STATOR RTD TRIPS
0797 BEARING RTD TRIPS
0798 OTHER RTD TRIPS
0799 AMBIENT RTD TRIPS
079A THERMAL MODEL TRIPS
079B INADVERTENT ENERG. TRIPS
079C ANALOG INPUT 1 TRIPS
079D ANALOG INPUT 2 TRIPS
079E ANALOG INPUT 3 TRIPS
079F ANALOG INPUT 4 TRIPS
MAINTENANCE / GENERAL COUNTERS
07A0 NUMBER OF BREAKER OPERATIONS
07A1 NUMBER OF THERMAL RESETS
MAINTENANCE / TRIP COUNTERS
07A2 LOSS OF EXCITATION 1 TRIPS
07A3 LOSS OF EXCITATION 2 TRIPS
07A4 GROUND DIRECTIONAL TRIPS
07A5 HIGH-SET PHASE O/C TRIPS
07A6 DISTANCE ZONE 1 TRIPS
07A7 DISTANCE ZONE 2 TRIPS
MAINTENANCE / TIMERS
07E0 GENERATOR HOURS ONLINE
PRODUCT INFO. / 489 MODEL INFO.
0800 ORDER CODE
0801 489 SERIAL NUMBER
PRODUCT INFO. / CALIBRATION INFO.
0810 ORIGINAL CALIBRATION DATE
0812 LAST CALIBRATION DATE
489 SETUP / PREFERENCES
1000 DEFAULT MESSAGE CYCLE TIME
1001 DEFAULT MESSAGE TIMEOUT
1003 PARAMETER AVERAGES CALC. PERIOD
1004 TEMPERATURE DISPLAY
1005 WAVEFORM TRIGGER POSITION
1006 PASSCODE (WRITE ONLY)
1008 ENCRYPTED PASSCODE (READ ONLY)
100A WAVEFORM MEMORY BUFFER
1, 2, 3
See Table footnotes on page 6–33
GE Multilin
RANGE
–50000 to 50000
–50000 to 50000
–50000 to 50000
–50000 to 50000
–50000 to 50000
STEP
1
1
1
1
1
UNITS
Units
Units
Units
Units
Units
FORMAT
F12
F12
F12
F12
F12
DEFAULT
0
0
0
0
0
N/A
0 to 50000
0 to 50000
0 to 50000
0 to 50000
0 to 50000
0 to 50000
0 to 50000
0 to 50000
0 to 50000
0 to 50000
0 to 50000
0 to 50000
0 to 50000
0 to 50000
0 to 50000
0 to 50000
0 to 50000
0 to 50000
0 to 50000
0 to 50000
0 to 50000
0 to 50000
0 to 50000
0 to 50000
0 to 50000
0 to 50000
0 to 50000
0 to 50000
0 to 50000
0 to 50000
0 to 50000
N/A
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
N/A
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
F18
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
N/A
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0 to 50000
0 to 50000
1
1
–
–
F1
F1
0
0
0 to 50000
0 to 50000
0 to 50000
0 to 50000
0 to 50000
0 to 50000
1
1
1
1
1
1
–
–
–
–
–
–
F1
F1
F1
F1
F1
F1
0
0
0
0
0
0
0 to 1000000
1
h
F12
0
0 to 65535
3000000 to 9999999
1
1
N/A
–
F136
F12
N/A
3000000
N/A
N/A
N/A
N/A
N/A
N/A
F18
F18
N/A
N/A
5 to 100
10 to 900
1 to 90
0 to 1
1 to 100
0 to 99999999
N/A
1 to 16
5
1
1
1
1
1
N/A
1
s
s
min
–
%
N/A
N/A
–
F2
F1
F1
F100
F1
F12
F12
F1
20
300
15
0
25
0
N/A
8
489 Generator Management Relay
6
6-15
6.3 MODBUS MEMORY MAP
6 COMMUNICATIONS
Table 6–1: 489 MEMORY MAP (SHEET 7 OF 24)
6
ADDR NAME
489 SETUP / SERIAL PORTS
1010 SLAVE ADDRESS
1011 COMPUTER RS485 BAUD RATE
1012 COMPUTER RS485 PARITY
1013 AUXILIARY RS485 BAUD RATE
1014 AUXILIARY RS485 PARITY
1015 PORT USED FOR DNP
1016 DNP SLAVE ADDRESS
1017 DNP TURNAROUND TIME
489 SETUP / REAL TIME CLOCK
1030 DATE
1032 TIME
1034 IRIG-B TYPE
489 SETUP / MESSAGE SCRATCHPAD
1060 Scratchpad
1080 Scratchpad
10A0 Scratchpad
10C0 Scratchpad
10E0 Scratchpad
489 SETUP / CLEAR DATA
1130 CLEAR LAST TRIP DATA
1131 CLEAR MWh and Mvarh METERS
1132 CLEAR PEAK DEMAND DATA
1133 CLEAR RTD MAXIMUMS
1134 CLEAR ANALOG I/P MIN/MAX
1135 CLEAR TRIP COUNTERS
1136 CLEAR EVENT RECORD
1137 CLEAR GENERATOR INFORMATION
1138 CLEAR BREAKER INFORMATION
SYSTEM SETUP / CURRENT SENSING
1180 PHASE CT PRIMARY
1181 GROUND CT
1182 GROUND CT RATIO
SYSTEM SETUP / VOLTAGE SENSING
11A0 VT CONNECTION TYPE
11A1 VOLTAGE TRANSFORMER RATIO
11A2 NEUTRAL V.T. RATIO
11A3 NEUTRAL VOLTAGE TRANSFORMER
SYSTEM SETUP / GEN. PARAMETERS
11C0 GENERATOR RATED MVA
11C2 GENERATOR RATED POWER FACTOR
11C3 GENERATOR VOLTAGE PHASE-PHASE
11C4 GENERATOR NOMINAL FREQUENCY
11C5 GENERATOR PHASE SEQUENCE
SYSTEM SETUP / SERIAL START/STOP
11E0 SERIAL START/STOP INITIATION
11E1 STARTUP INITIATION RELAYS (2-5)
11E2 SHUTDOWN INITIATION RELAYS (1-4)
11E3 SERIAL START/STOP EVENTS
DIGITAL INPUTS / BREAKER STATUS
1200 BREAKER STATUS
DIGITAL INPUTS / GENERAL INPUT A
1210 ASSIGN DIGITAL INPUT
1211 ASSERTED DIGITAL INPUT STATE
1212 INPUT NAME
1218 BLOCK INPUT FROM ONLINE
1219 GENERAL INPUT A CONTROL
121A PULSED CONTROL RELAY DWELL TIME
121B ASSIGN CONTROL RELAYS (1-5)
121C GENERAL INPUT A CONTROL EVENTS
121D GENERAL INPUT A ALARM
121E ASSIGN ALARM RELAYS (2-5)
121F GENERAL INPUT A ALARM DELAY
1220 GENERAL INPUT A ALARM EVENTS
1221 GENERAL INPUT A TRIP
1222 ASSIGN TRIP RELAYS (1-4)
1, 2, 3
See Table footnotes on page 6–33
6-16
RANGE
STEP
UNITS
FORMAT
DEFAULT
1 to 254
0 to 5
0 to 2
0 to 5
0 to 2
0 to 3
0 to 255
0 to 100
1
1
1
1
1
1
1
10
–
–
–
–
–
–
–
ms
F1
F101
F102
F101
F102
F216
F1
F1
254
4
0
4
0
0
255
10
N/A
N/A
0 to 2
N/A
N/A
1
N/A
N/A
–
F18
F19
F220
N/A
N/A
0
0 to 40
0 to 40
0 to 40
0 to 40
0 to 40
1
1
1
1
1
–
–
–
–
–
F22
F22
F22
F22
F22
_
_
_
_
_
0 to 1
0 to 1
0 to 1
0 to 1
0 to 1
0 to 1
0 to 1
0 to 1
0 to 1
1
1
1
1
1
1
1
1
1
–
–
–
–
–
–
–
–
–
F103
F103
F103
F103
F103
F103
F103
F103
F103
0
0
0
0
0
0
0
0
0
10 to 50001
0 to 3
10 to 10000
1
1
1
Amps
–
: 1 / :5
F1
F104
F1
50001
0
100
0 to 2
100 to 30000
100 to 24000
0 to 1
1
1
1
1
–
:1
:1
–
F106
F3
F3
F103
0
500
500
0
50 to 2000001
5 to 100
100 to 30001
0 to 3
0 to 2
1
1
1
1
1
MVA
–
V
Hz
–
F13
F3
F1
F107
F124
2000001
100
30001
0
0
0 to 1
1 to 4
0 to 3
0 to 1
1
1
1
1
–
–
–
–
F105
F50
F50
F105
0
0
0
0
0 to 1
1
–
F209
1
0 to 7
0 to 1
0 to 12
0 to 5000
0 to 1
0 to 250
0 to 4
0 to 1
0 to 2
1 to 4
1 to 50000
0 to 1
0 to 2
0 to 3
1
1
1
1
1
1
1
1
1
1
1
1
1
1
–
–
–
s
–
s
–
–
–
–
s
–
–
–
F210
F131
F22
F1
F105
F2
F50
F105
F115
F50
F2
F105
F115
F50
0
0
_
0
0
0
0
0
0
16
50
0
0
1
489 Generator Management Relay
GE Multilin
6 COMMUNICATIONS
6.3 MODBUS MEMORY MAP
Table 6–1: 489 MEMORY MAP (SHEET 8 OF 24)
ADDR NAME
1223 GENERAL INPUT A TRIP DELAY
DIGITAL INPUTS / GENERAL INPUT B
1230 ASSIGN DIGITAL INPUT
1231 ASSERTED DIGITAL INPUT STATE
1232 INPUT NAME
1238 BLOCK INPUT FROM ONLINE
1239 GENERAL INPUT B CONTROL
123A PULSED CONTROL RELAY DWELL TIME
123B ASSIGN CONTROL RELAYS (1-5)
123C GENERAL INPUT B CONTROL EVENTS
123D GENERAL INPUT B ALARM
123E ASSIGN ALARM RELAYS (2-5)
123F GENERAL INPUT B ALARM DELAY
1240 GENERAL INPUT B ALARM EVENTS
1241 GENERAL INPUT B TRIP
1242 ASSIGN TRIP RELAYS (1-4)
1243 GENERAL INPUT B TRIP DELAY
DIGITAL INPUTS / GENERAL INPUT C
1250 ASSIGN DIGITAL INPUT
1251 ASSERTED DIGITAL INPUT STATE
1252 INPUT NAME
1258 BLOCK INPUT FROM ONLINE
1259 GENERAL INPUT C CONTROL
125A PULSED CONTROL RELAY DWELL TIME
125B ASSIGN CONTROL RELAYS (1-5)
125C GENERAL INPUT C CONTROL EVENTS
125D GENERAL INPUT C ALARM
125E ASSIGN ALARM RELAYS (2-5)
125F GENERAL INPUT C ALARM DELAY
1260 GENERAL INPUT C ALARM EVENTS
1261 GENERAL INPUT C TRIP
1262 ASSIGN TRIP RELAYS (1-4)
1263 GENERAL INPUT C TRIP DELAY
DIGITAL INPUTS / GENERAL INPUT D
1270 ASSIGN DIGITAL INPUT
1271 ASSERTED DIGITAL INPUT STATE
1272 INPUT NAME
1278 BLOCK INPUT FROM ONLINE
1279 GENERAL INPUT D CONTROL
127A PULSED CONTROL RELAY DWELL TIME
127B ASSIGN CONTROL RELAYS (1-5)
127C GENERAL INPUT D CONTROL EVENTS
127D GENERAL INPUT D ALARM
127E ASSIGN ALARM RELAYS (2-5)
127F GENERAL INPUT D ALARM DELAY
1280 GENERAL INPUT D ALARM EVENTS
1281 GENERAL INPUT D TRIP
1282 ASSIGN TRIP RELAYS (1-4)
1283 GENERAL INPUT D TRIP DELAY
DIGITAL INPUTS / GENERAL INPUT E
1290 ASSIGN DIGITAL INPUT
1291 ASSERTED DIGITAL INPUT STATE
1292 INPUT NAME
1298 BLOCK INPUT FROM ONLINE
1299 GENERAL INPUT E CONTROL
129A PULSED CONTROL RELAY DWELL TIME
129B ASSIGN CONTROL RELAYS (1-5)
129C GENERAL INPUT E CONTROL EVENTS
129D GENERAL INPUT E ALARM
129E ASSIGN ALARM RELAYS (2-5)
129F GENERAL INPUT E ALARM DELAY
12A0 GENERAL INPUT E ALARM EVENTS
12A1 GENERAL INPUT E TRIP
12A2 ASSIGN TRIP RELAYS (1-4)
12A3 GENERAL INPUT E TRIP DELAY
1, 2, 3
See Table footnotes on page 6–33
GE Multilin
RANGE
1 to 50000
STEP
1
UNITS
s
FORMAT
F2
DEFAULT
50
0 to 7
0 to 1
0 to 12
0 to 5000
0 to 1
0 to 250
0 to 4
0 to 1
0 to 2
1 to 4
1 to 50000
0 to 1
0 to 2
0 to 3
1 to 50000
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
–
–
–
s
–
s
–
–
–
–
s
–
–
–
s
F210
F131
F22
F1
F105
F2
F50
F105
F115
F50
F2
F105
F115
F50
F2
0
0
_
0
0
0
0
0
0
16
50
0
0
1
50
0 to 7
0 to 1
0 to 12
0 to 5000
0 to 1
0 to 250
0 to 4
0 to 1
0 to 2
1 to 4
1 to 50000
0 to 1
0 to 2
0 to 3
1 to 50000
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
–
–
–
s
–
s
–
–
–
–
s
–
–
–
s
F210
F131
F22
F1
F105
F2
F50
F105
F115
F50
F2
F105
F115
F50
F2
0
0
_
0
0
0
0
0
0
16
50
0
0
1
50
0 to 7
0 to 1
0 to 12
0 to 5000
0 to 1
0 to 250
0 to 4
0 to 1
0 to 2
1 to 4
1 to 50000
0 to 1
0 to 2
0 to 3
1 to 50000
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
–
–
–
s
–
s
–
–
–
–
s
–
–
–
s
F210
F131
F22
F1
F105
F2
F50
F105
F115
F50
F2
F105
F115
F50
F2
0
0
_
0
0
0
0
0
0
16
50
0
0
1
50
0 to 7
0 to 1
0 to 12
0 to 5000
0 to 1
0 to 250
0 to 4
0 to 1
0 to 2
1 to 4
1 to 50000
0 to 1
0 to 2
0 to 3
1 to 50000
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
–
–
–
s
–
s
–
–
–
–
s
–
–
–
s
F210
F131
F22
F1
F105
F2
F50
F105
F115
F50
F2
F105
F115
F50
F2
0
0
_
0
0
0
0
0
0
16
50
0
0
1
50
489 Generator Management Relay
6
6-17
6.3 MODBUS MEMORY MAP
6 COMMUNICATIONS
Table 6–1: 489 MEMORY MAP (SHEET 9 OF 24)
6
ADDR NAME
DIGITAL INPUTS / GENERAL INPUT F
12B0 ASSIGN DIGITAL INPUT
12B1 ASSERTED DIGITAL INPUT STATE
12B2 INPUT NAME
12B8 BLOCK INPUT FROM ONLINE
12B9 GENERAL INPUT F CONTROL
12BA PULSED CONTROL RELAY DWELL TIME
12BB ASSIGN CONTROL RELAYS (1-5)
12BC GENERAL INPUT F CONTROL EVENTS
12BD GENERAL INPUT F ALARM
12BE ASSIGN ALARM RELAYS (2-5)
12BF GENERAL INPUT F ALARM DELAY
12C0 GENERAL INPUT F ALARM EVENTS
12C1 GENERAL INPUT F TRIP
12C2 ASSIGN TRIP RELAYS (1-4)
12C3 GENERAL INPUT F TRIP DELAY
DIGITAL INPUTS / GENERAL INPUT G
12D0 ASSIGN DIGITAL INPUT
12D1 ASSERTED DIGITAL INPUT STATE
12D2 INPUT NAME
12D8 BLOCK INPUT FROM ONLINE
12D9 GENERAL INPUT G CONTROL
12DA PULSED CONTROL RELAY DWELL TIME
12DB ASSIGN CONTROL RELAYS (1-5)
12DC GENERAL INPUT G CONTROL EVENTS
12DD GENERAL INPUT G ALARM
12DE ASSIGN ALARM RELAYS (2-5)
12DF GENERAL INPUT G ALARM DELAY
12E0 GENERAL INPUT G ALARM EVENTS
12E1 GENERAL INPUT G TRIP
12E2 ASSIGN TRIP RELAYS (1-4)
12E3 GENERAL INPUT G TRIP DELAY
DIGITAL INPUTS / REMOTE RESET
1300 ASSIGN DIGITAL INPUT
DIGITAL INPUTS / TEST INPUT
1310 ASSIGN DIGITAL INPUT
DIGITAL INPUTS / THERMAL RESET
1320 ASSIGN DIGITAL INPUT
DIGITAL INPUTS / DUAL SETPOINTS
1340 ASSIGN DIGITAL INPUT
1341 ACTIVE SETPOINT GROUP
1342 EDIT SETPOINT GROUP
DIGITAL INPUTS / SEQUENTIAL TRIP
1360 ASSIGN DIGITAL INPUT
1361 SEQUENTIAL TRIP TYPE
1362 ASSIGN TRIP RELAYS (1-4)
1363 SEQUENTIAL TRIP LEVEL
1365 SEQUENTIAL TRIP DELAY
DIGITAL INPUTS / FIELD-BKR DISCREP.
1380 ASSIGN DIGITAL INPUT
1381 FIELD STATUS CONTACT
1382 ASSIGN TRIP RELAYS (1-4)
1383 FIELD-BKR DISCREP. TRIP DELAY
DIGITAL INPUTS / TACHOMETER
13A0 ASSIGN DIGITAL INPUT
13A1 RATED SPEED
13A2 TACHOMETER ALARM
13A3 ASSIGN ALARM RELAYS (2-5)
13A4 TACHOMETER ALARM SPEED
13A5 TACHOMETER ALARM DELAY
13A6 TACHOMETER ALARM EVENTS
13A7 TACHOMETER TRIP
13A8 ASSIGN TRIP RELAYS (1-4)
13A9 TACHOMETER TRIP SPEED
13AA TACHOMETER TRIP DELAY
1, 2, 3
See Table footnotes on page 6–33
6-18
RANGE
STEP
UNITS
FORMAT
DEFAULT
0 to 7
0 to 1
0 to 12
0 to 5000
0 to 1
0 to 250
0 to 4
0 to 1
0 to 2
1 to 4
1 to 50000
0 to 1
0 to 2
0 to 3
1 to 50000
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
–
–
–
s
–
s
–
–
–
–
s
–
–
–
s
F210
F131
F22
F1
F105
F2
F50
F105
F115
F50
F2
F105
F115
F50
F2
0
0
_
0
0
0
0
0
0
16
50
0
0
1
50
0 to 7
0 to 1
0 to 12
0 to 5000
0 to 1
0 to 250
0 to 4
0 to 1
0 to 2
1 to 4
1 to 50000
0 to 1
0 to 2
0 to 3
1 to 50000
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
–
–
–
s
–
s
–
–
–
–
s
–
–
–
s
F210
F131
F22
F1
F105
F2
F50
F105
F115
F50
F2
F105
F115
F50
F2
0
0
_
0
0
0
0
0
0
16
50
0
0
1
50
0 to 7
1
–
F210
0
0 to 7
1
–
F210
0
0 to 7
1
–
F210
0
0 to 7
0 to 1
0 to 1
1
1
1
–
–
–
F210
F118
F118
0
0
0
0 to 7
0 to 1
0 to 3
2 to 99
2 to 1200
1
1
1
1
1
–
–
–
× Rated MW
s
F210
F206
F50
F14
F2
0
0
1
5
10
0 to 7
0 to 1
0 to 3
1 to 5000
1
1
1
1
–
–
–
s
F210
F109
F50
F2
0
0
1
10
0 to 7
100 to 3600
0 to 2
1 to 4
101 to 175
1 to 250
0 to 1
0 to 2
0 to 3
101 to 175
1 to 250
1
1
1
1
1
1
1
1
1
1
1
–
RPM
–
–
%Rated
s
–
–
–
%Rated
s
F210
F1
F115
F50
F1
F1
F105
F115
F50
F1
F1
0
3600
0
16
110
1
0
0
1
110
1
489 Generator Management Relay
GE Multilin
6 COMMUNICATIONS
6.3 MODBUS MEMORY MAP
Table 6–1: 489 MEMORY MAP (SHEET 10 OF 24)
ADDR NAME
DIGITAL INPUTS / WAVEFORM CAPTURE
13C0 ASSIGN DIGITAL INPUT
DIGITAL INPUTS / GND. SWITCH STATUS
13D0 ASSIGN DIGITAL INPUT
13D1 GROUND SWITCH CONTACT
OUTPUT RELAYS / RELAY RESET MODE
1400 R1 TRIP
1401 R2 AUXILIARY
1402 R3 AUXILIARY
1403 R4 AUXILIARY
1404 R5 ALARM
1405 R6 SERVICE
CURRENT ELEMENTS / OVERCURRENT ALARM
1500 OVERCURRENT ALARM
1501 ASSIGN ALARM RELAYS (2-5)
1502 OVERCURRENT ALARM LEVEL
1503 OVERCURRENT ALARM DELAY
1504 OVERCURRENT ALARM EVENTS
CURRENT ELEMENTS / OFFLINE O/C
1520 OFFLINE OVERCURRENT TRIP
1521 ASSIGN TRIP RELAYS (1-4)
1522 OFFLINE OVERCURRENT PICKUP
1523 OFFLINE OVERCURRENT TRIP DELAY
CURRENT ELEMENTS / INADVERTENT ENERG.
1540 INADVERTENT ENERGIZE TRIP
1541 ASSIGN TRIP RELAYS (1-4)
1542 ARMING SIGNAL
1543 INADVERTENT ENERGIZE O/C PICKUP
1544 INADVERTENT ENERGIZE PICKUP
CURRENT ELEMENTS / PHASE OVERCURRENT
1600 PHASE OVERCURRENT TRIP
1601 ASSIGN TRIP RELAYS (1-4)
1602 ENABLE VOLTAGE RESTRAINT
1603 PHASE OVERCURRENT PICKUP
1604 CURVE SHAPE
1605 FLEXCURVE TRIP TIME AT 1.03 × PU
1606 FLEXCURVE TRIP TIME AT 1.05 × PU
1607 FLEXCURVE TRIP TIME AT 1.10 × PU
1608 FLEXCURVE TRIP TIME AT 1.20 × PU
1609 FLEXCURVE TRIP TIME AT 1.30 × PU
160A FLEXCURVE TRIP TIME AT 1.40 × PU
160B FLEXCURVE TRIP TIME AT 1.50 × PU
160C FLEXCURVE TRIP TIME AT 1.60 × PU
160D FLEXCURVE TRIP TIME AT 1.70 × PU
160E FLEXCURVE TRIP TIME AT 1.80 × PU
160F FLEXCURVE TRIP TIME AT 1.90 × PU
1610 FLEXCURVE TRIP TIME AT 2.00 × PU
1611 FLEXCURVE TRIP TIME AT 2.10 × PU
1612 FLEXCURVE TRIP TIME AT 2.20 × PU
1613 FLEXCURVE TRIP TIME AT 2.30 × PU
1614 FLEXCURVE TRIP TIME AT 2.40 × PU
1615 FLEXCURVE TRIP TIME AT 2.50 × PU
1616 FLEXCURVE TRIP TIME AT 2.60 × PU
1617 FLEXCURVE TRIP TIME AT 2.70 × PU
1618 FLEXCURVE TRIP TIME AT 2.80 × PU
1619 FLEXCURVE TRIP TIME AT 2.90 × PU
161A FLEXCURVE TRIP TIME AT 3.00 × PU
161B FLEXCURVE TRIP TIME AT 3.10 × PU
161C FLEXCURVE TRIP TIME AT 3.20 × PU
161D FLEXCURVE TRIP TIME AT 3.30 × PU
161E FLEXCURVE TRIP TIME AT 3.40 × PU
161F FLEXCURVE TRIP TIME AT 3.50 × PU
1620 FLEXCURVE TRIP TIME AT 3.60 × PU
1621 FLEXCURVE TRIP TIME AT 3.70 × PU
1622 FLEXCURVE TRIP TIME AT 3.80 × PU
1623 FLEXCURVE TRIP TIME AT 3.90 × PU
1, 2, 3
See Table footnotes on page 6–33
GE Multilin
RANGE
STEP
UNITS
FORMAT
DEFAULT
0 to 7
1
–
F210
0
0 to 7
0 to 1
1
1
–
–
F210
F109
0
0
0 to 1
0 to 1
0 to 1
0 to 1
0 to 1
0 to 1
1
1
1
1
1
1
–
–
–
–
–
–
F117
F117
F117
F117
F117
F117
0
0
0
0
0
0
0 to 2
1 to 4
10 to 150
1 to 2500
0 to 1
1
1
1
1
1
–
–
× FLA
s
–
F115
F50
F3
F2
F105
0
16
101
1
0
0 to 2
0 to 3
5 to 100
3 to 99
1
1
1
1
–
–
× CT
Cycles
F115
F50
F3
F1
0
1
5
5
0 to 2
0 to 3
0 to 1
5 to 300
50 to 99
1
1
1
1
1
–
–
–
× CT
× Rated V
F115
F50
F202
F3
F3
0
1
0
5
50
0 to 2
0 to 3
0 to 1
15 to 2000
0 to 13
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
–
–
–
× CT
–
ms
ms
ms
ms
ms
ms
ms
ms
ms
ms
ms
ms
ms
ms
ms
ms
ms
ms
ms
ms
ms
ms
ms
ms
ms
ms
ms
ms
ms
ms
ms
F115
F50
F103
F3
F128
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
0
1
0
1000
0
65535
65535
65535
65535
65535
65535
65535
65535
65535
65535
65535
65535
65535
65535
65535
65535
65535
65535
65535
65535
65535
65535
65535
65535
65535
65535
65535
65535
65535
65535
65535
489 Generator Management Relay
6-19
6
6.3 MODBUS MEMORY MAP
6 COMMUNICATIONS
Table 6–1: 489 MEMORY MAP (SHEET 11 OF 24)
6
ADDR NAME
1624 FLEXCURVE TRIP TIME AT 4.00 × PU
1625 FLEXCURVE TRIP TIME AT 4.10 × PU
1626 FLEXCURVE TRIP TIME AT 4.20 × PU
1627 FLEXCURVE TRIP TIME AT 4.30 × PU
1628 FLEXCURVE TRIP TIME AT 4.40 × PU
1629 FLEXCURVE TRIP TIME AT 4.50 × PU
162A FLEXCURVE TRIP TIME AT 4.60 × PU
162B FLEXCURVE TRIP TIME AT 4.70 × PU
162C FLEXCURVE TRIP TIME AT 4.80 × PU
162D FLEXCURVE TRIP TIME AT 4.90 × PU
162E FLEXCURVE TRIP TIME AT 5.00 × PU
162F FLEXCURVE TRIP TIME AT 5.10 × PU
1630 FLEXCURVE TRIP TIME AT 5.20 × PU
1631 FLEXCURVE TRIP TIME AT 5.30 × PU
1632 FLEXCURVE TRIP TIME AT 5.40 × PU
1633 FLEXCURVE TRIP TIME AT 5.50 × PU
1634 FLEXCURVE TRIP TIME AT 5.60 × PU
1635 FLEXCURVE TRIP TIME AT 5.70 × PU
1636 FLEXCURVE TRIP TIME AT 5.80 × PU
1637 FLEXCURVE TRIP TIME AT 5.90 × PU
1638 FLEXCURVE TRIP TIME AT 6.00 × PU
1639 FLEXCURVE TRIP TIME AT 6.50 × PU
163A FLEXCURVE TRIP TIME AT 7.00 × PU
163B FLEXCURVE TRIP TIME AT 7.50 × PU
163C FLEXCURVE TRIP TIME AT 8.00 × PU
163D FLEXCURVE TRIP TIME AT 8.50 × PU
163E FLEXCURVE TRIP TIME AT 9.00 × PU
163F FLEXCURVE TRIP TIME AT 9.50 × PU
1640 FLEXCURVE TRIP TIME AT 10.0 × PU
1641 FLEXCURVE TRIP TIME AT 10.5 × PU
1642 FLEXCURVE TRIP TIME AT 11.0 × PU
1643 FLEXCURVE TRIP TIME AT 11.5 × PU
1644 FLEXCURVE TRIP TIME AT 12.0 × PU
1645 FLEXCURVE TRIP TIME AT 12.5 × PU
1646 FLEXCURVE TRIP TIME AT 13.0 × PU
1647 FLEXCURVE TRIP TIME AT 13.5 × PU
1648 FLEXCURVE TRIP TIME AT 14.0 × PU
1649 FLEXCURVE TRIP TIME AT 14.5 × PU
164A FLEXCURVE TRIP TIME AT 15.0 × PU
164B FLEXCURVE TRIP TIME AT 15.5 × PU
164C FLEXCURVE TRIP TIME AT 16.0 × PU
164D FLEXCURVE TRIP TIME AT 16.5 × PU
164E FLEXCURVE TRIP TIME AT 17.0 × PU
164F FLEXCURVE TRIP TIME AT 17.5 × PU
1650 FLEXCURVE TRIP TIME AT 18.0 × PU
1651 FLEXCURVE TRIP TIME AT 18.5 × PU
1652 FLEXCURVE TRIP TIME AT 19.0 × PU
1653 FLEXCURVE TRIP TIME AT 19.5 × PU
1654 FLEXCURVE TRIP TIME AT 20.0 × PU
1655 OVERCURRENT CURVE MULTIPLIER
1657 OVERCURRENT CURVE RESET
1658 VOLTAGE LOWER LIMIT
CURRENT ELEMENTS / NEGATIVE SEQUENCE
1700 NEGATIVE SEQUENCE ALARM
1701 ASSIGN ALARM RELAYS (2-5)
1702 NEG. SEQUENCE ALARM PICKUP
1703 NEGATIVE SEQUENCE ALARM DELAY
1704 NEGATIVE SEQUENCE ALARM EVENTS
1705 NEGATIVE SEQUENCE O/C TRIP
1706 ASSIGN TRIP RELAYS (1-4)
1707 NEG. SEQUENCE O/C TRIP PICKUP
1708 NEG. SEQUENCE O/C CONSTANT K
1709 NEG. SEQUENCE O/C MAX. TIME
170A NEG. SEQUENCE O/C RESET RATE
1, 2, 3
See Table footnotes on page 6–33
6-20
RANGE
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 100000
0 to 1
10 to 60
STEP
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
UNITS
ms
ms
ms
ms
ms
ms
ms
ms
ms
ms
ms
ms
ms
ms
ms
ms
ms
ms
ms
ms
ms
ms
ms
ms
ms
ms
ms
ms
ms
ms
ms
ms
ms
ms
ms
ms
ms
ms
ms
ms
ms
ms
ms
ms
ms
ms
ms
ms
ms
–
–
%
FORMAT
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F14
F201
F1
DEFAULT
65535
65535
65535
65535
65535
65535
65535
65535
65535
65535
65535
65535
65535
65535
65535
65535
65535
65535
65535
65535
65535
65535
65535
65535
65535
65535
65535
65535
65535
65535
65535
65535
65535
65535
65535
65535
65535
65535
65535
65535
65535
65535
65535
65535
65535
65535
65535
65535
65535
100
0
10
0 to 2
1 to 4
3 to 100
1 to 1000
0 to 1
0 to 2
0 to 3
3 to 100
1 to 100
10 to 1000
0 to 9999
1
1
1
1
1
1
1
1
1
1
1
–
–
%FLA
s
–
–
–
%FLA
–
s
s
F115
F50
F1
F2
F105
F115
F50
F1
F1
F1
F2
0
16
3
50
0
0
1
8
1
1000
2270
489 Generator Management Relay
GE Multilin
6 COMMUNICATIONS
6.3 MODBUS MEMORY MAP
Table 6–1: 489 MEMORY MAP (SHEET 12 OF 24)
ADDR NAME
CURRENT ELEMENTS / GROUND O/C
1720 GROUND OVERCURRENT ALARM
1721 ASSIGN ALARM RELAYS (2-5)
1722 GROUND O/C ALARM PICKUP
1723 GROUND O/C ALARM DELAY
1724 GROUND OVERCURRENT ALARM EVENTS
1725 GROUND OVERCURRENT TRIP
1726 ASSIGN TRIP RELAYS (1-4)
1727 GROUND O/C TRIP PICKUP
1728 CURVE SHAPE
1729 FLEXCURVE TRIP TIME AT 1.03 × PU
172A FLEXCURVE TRIP TIME AT 1.05 × PU
172B FLEXCURVE TRIP TIME AT 1.10 × PU
172C FLEXCURVE TRIP TIME AT 1.20 × PU
172D FLEXCURVE TRIP TIME AT 1.30 × PU
172E FLEXCURVE TRIP TIME AT 1.40 × PU
172F FLEXCURVE TRIP TIME AT 1.50 × PU
1730 FLEXCURVE TRIP TIME AT 1.60 × PU
1731 FLEXCURVE TRIP TIME AT 1.70 × PU
1732 FLEXCURVE TRIP TIME AT 1.80 × PU
1733 FLEXCURVE TRIP TIME AT 1.90 × PU
1734 FLEXCURVE TRIP TIME AT 2.00 × PU
1735 FLEXCURVE TRIP TIME AT 2.10 × PU
1736 FLEXCURVE TRIP TIME AT 2.20 × PU
1737 FLEXCURVE TRIP TIME AT 2.30 × PU
1738 FLEXCURVE TRIP TIME AT 2.40 × PU
1739 FLEXCURVE TRIP TIME AT 2.50 × PU
173A FLEXCURVE TRIP TIME AT 2.60 × PU
173B FLEXCURVE TRIP TIME AT 2.70 × PU
173C FLEXCURVE TRIP TIME AT 2.80 × PU
173D FLEXCURVE TRIP TIME AT 2.90 × PU
173E FLEXCURVE TRIP TIME AT 3.00 × PU
173F FLEXCURVE TRIP TIME AT 3.10 × PU
1740 FLEXCURVE TRIP TIME AT 3.20 × PU
1741 FLEXCURVE TRIP TIME AT 3.30 × PU
1742 FLEXCURVE TRIP TIME AT 3.40 × PU
1743 FLEXCURVE TRIP TIME AT 3.50 × PU
1744 FLEXCURVE TRIP TIME AT 3.60 × PU
1745 FLEXCURVE TRIP TIME AT 3.70 × PU
1746 FLEXCURVE TRIP TIME AT 3.80 × PU
1747 FLEXCURVE TRIP TIME AT 3.90 × PU
1748 FLEXCURVE TRIP TIME AT 4.00 × PU
1749 FLEXCURVE TRIP TIME AT 4.10 × PU
174A FLEXCURVE TRIP TIME AT 4.20 × PU
174B FLEXCURVE TRIP TIME AT 4.30 × PU
174C FLEXCURVE TRIP TIME AT 4.40 × PU
174D FLEXCURVE TRIP TIME AT 4.50 × PU
174E FLEXCURVE TRIP TIME AT 4.60 × PU
174F FLEXCURVE TRIP TIME AT 4.70 × PU
1750 FLEXCURVE TRIP TIME AT 4.80 × PU
1751 FLEXCURVE TRIP TIME AT 4.90 × PU
1752 FLEXCURVE TRIP TIME AT 5.00 × PU
1753 FLEXCURVE TRIP TIME AT 5.10 × PU
1754 FLEXCURVE TRIP TIME AT 5.20 × PU
1755 FLEXCURVE TRIP TIME AT 5.30 × PU
1756 FLEXCURVE TRIP TIME AT 5.40 × PU
1757 FLEXCURVE TRIP TIME AT 5.50 × PU
1758 FLEXCURVE TRIP TIME AT 5.60 × PU
1759 FLEXCURVE TRIP TIME AT 5.70 × PU
175A FLEXCURVE TRIP TIME AT 5.80 × PU
175B FLEXCURVE TRIP TIME AT 5.90 × PU
175C FLEXCURVE TRIP TIME AT 6.00 × PU
175D FLEXCURVE TRIP TIME AT 6.50 × PU
175E FLEXCURVE TRIP TIME AT 7.00 × PU
175F FLEXCURVE TRIP TIME AT 7.50 × PU
1760 FLEXCURVE TRIP TIME AT 8.00 × PU
1, 2, 3
See Table footnotes on page 6–33
GE Multilin
RANGE
STEP
UNITS
FORMAT
DEFAULT
0 to 2
1 to 4
5 to 2000
0 to 100
0 to 1
0 to 2
0 to 3
5 to 2000
0 to 13
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
–
–
× CT
Cycles
–
–
–
× CT
–
ms
ms
ms
ms
ms
ms
ms
ms
ms
ms
ms
ms
ms
ms
ms
ms
ms
ms
ms
ms
ms
ms
ms
ms
ms
ms
ms
ms
ms
ms
ms
ms
ms
ms
ms
ms
ms
ms
ms
ms
ms
ms
ms
ms
ms
ms
ms
ms
ms
ms
ms
ms
ms
ms
ms
ms
F115
F50
F3
F1
F105
F115
F50
F3
F128
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
0
16
20
0
0
0
1
20
0
65535
65535
65535
65535
65535
65535
65535
65535
65535
65535
65535
65535
65535
65535
65535
65535
65535
65535
65535
65535
65535
65535
65535
65535
65535
65535
65535
65535
65535
65535
65535
65535
65535
65535
65535
65535
65535
65535
65535
65535
65535
65535
65535
65535
65535
65535
65535
65535
65535
65535
65535
65535
65535
65535
65535
65535
489 Generator Management Relay
6-21
6
6.3 MODBUS MEMORY MAP
6 COMMUNICATIONS
Table 6–1: 489 MEMORY MAP (SHEET 13 OF 24)
6
ADDR NAME
1761 FLEXCURVE TRIP TIME AT 8.50 × PU
1762 FLEXCURVE TRIP TIME AT 9.00 × PU
1763 FLEXCURVE TRIP TIME AT 9.50 × PU
1764 FLEXCURVE TRIP TIME AT 10.0 × PU
1765 FLEXCURVE TRIP TIME AT 10.5 × PU
1766 FLEXCURVE TRIP TIME AT 11.0 × PU
1767 FLEXCURVE TRIP TIME AT 11.5 × PU
1768 FLEXCURVE TRIP TIME AT 12.0 × PU
1769 FLEXCURVE TRIP TIME AT 12.5 × PU
176A FLEXCURVE TRIP TIME AT 13.0 × PU
176B FLEXCURVE TRIP TIME AT 13.5 × PU
176C FLEXCURVE TRIP TIME AT 14.0 × PU
176D FLEXCURVE TRIP TIME AT 14.5 × PU
176E FLEXCURVE TRIP TIME AT 15.0 × PU
176F FLEXCURVE TRIP TIME AT 15.5 × PU
1770 FLEXCURVE TRIP TIME AT 16.0 × PU
1771 FLEXCURVE TRIP TIME AT 16.5 × PU
1772 FLEXCURVE TRIP TIME AT 17.0 × PU
1773 FLEXCURVE TRIP TIME AT 17.5 × PU
1774 FLEXCURVE TRIP TIME AT 18.0 × PU
1775 FLEXCURVE TRIP TIME AT 18.5 × PU
1776 FLEXCURVE TRIP TIME AT 19.0 × PU
1777 FLEXCURVE TRIP TIME AT 19.5 × PU
1778 FLEXCURVE TRIP TIME AT 20.0 × PU
1779 OVERCURRENT CURVE MULTIPLIER
177B OVERCURRENT CURVE RESET
CURRENT ELEMENTS / PHASE DIFFERENTIAL
17E0 PHASE DIFFERENTIAL TRIP
17E1 ASSIGN TRIP RELAYS (1-4)
17E2 DIFFERENTIAL TRIP MIN. PICKUP
17E3 DIFFERENTIAL TRIP SLOPE 1
17E4 DIFFERENTIAL TRIP SLOPE 2
17E5 DIFFERENTIAL TRIP DELAY
CURRENT ELEMENTS / GROUND DIRECTIONAL
1800 SUPERVISE WITH DIGITAL INPUT
1801 GROUND DIRECTIONAL MTA
1802 GROUND DIRECTIONAL ALARM
1803 ASSIGN ALARM RELAYS (2-5)
1804 GROUND DIR. ALARM PICKUP
1805 GROUND DIR. ALARM DELAY
1806 GROUND DIR. ALARM EVENTS
1807 GROUND DIRECTIONAL TRIP
1808 ASSIGN TRIP RELAYS (1-4)
1809 GROUND DIR. TRIP PICKUP
180A GROUND DIR. TRIP DELAY
CURRENT ELEMENTS / HIGH-SET PHASE O/C
1830 HIGH-SET PHASE O/C TRIP
1831 ASSIGN TRIP RELAYS (1-4)
1832 HIGH-SET PHASE O/C PICKUP
1833 HIGH-SET PHASE O/C DELAY
VOLTAGE ELEMENTS / UNDERVOLTAGE
2000 UNDERVOLTAGE ALARM
2001 ASSIGN ALARM RELAYS (2-5)
2002 UNDERVOLTAGE ALARM PICKUP
2003 UNDERVOLTAGE ALARM DELAY
2004 UNDERVOLTAGE ALARM EVENTS
2005 UNDERVOLTAGE TRIP
2006 ASSIGN TRIP RELAYS (1-4)
2007 UNDERVOLTAGE TRIP PICKUP
2008 UNDERVOLTAGE TRIP DELAY
2009 UNDERVOLTAGE CURVE RESET RATE
200A UNDERVOLTAGE CURVE ELEMENT
VOLTAGE ELEMENTS / OVERVOLTAGE
2020 OVERVOLTAGE ALARM
2021 ASSIGN ALARM RELAYS (2-5)
2022 OVERVOLTAGE ALARM PICKUP
1, 2, 3
See Table footnotes on page 6–33
6-22
RANGE
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 65535
0 to 100000
0 to 1
STEP
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
UNITS
ms
ms
ms
ms
ms
ms
ms
ms
ms
ms
ms
ms
ms
ms
ms
ms
ms
ms
ms
ms
ms
ms
ms
ms
–
–
FORMAT
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F1
F14
F201
DEFAULT
65535
65535
65535
65535
65535
65535
65535
65535
65535
65535
65535
65535
65535
65535
65535
65535
65535
65535
65535
65535
65535
65535
65535
65535
100
0
0 to 2
0 to 3
5 to 100
1 to 100
1 to 100
0 to 100
1
1
1
1
1
1
–
–
× CT
%
%
cycles
F115
F50
F3
F1
F1
F1
0
1
10
10
20
0
0 to 1
0 to 3
0 to 2
1 to 4
5 to 2000
1 to 1200
0 to 1
0 to 2
0 to 3
5 to 2000
1 to 1200
1
1
1
1
1
1
1
1
1
1
1
–
–
–
–
× CT
s
–
–
–
× CT
s
F103
F217
F115
F50
F3
F2
F105
F115
F50
F3
F2
1
0
0
16
5
30
0
0
1
5
30
0 to 2
0 to 3
15 to 2000
0 to 10000
1
1
1
1
–
–
× CT
s
F115
F50
F3
F3
0
1
500
100
0 to 2
1 to 4
50 to 99
2 to 1200
0 to 1
0 to 2
0 to 3
50 to 99
2 to 100
0 to 9999
0 to 1
1
1
1
1
1
1
1
1
1
1
1
–
–
× Rated
s
–
–
–
× Rated
s
s
–
F115
F50
F3
F2
F105
F115
F50
F3
F2
F2
F208
0
16
85
30
0
0
1
80
10
14
0
0 to 2
1 to 4
101 to 150
1
1
1
–
–
× Rated
F115
F50
F3
0
16
115
489 Generator Management Relay
GE Multilin
6 COMMUNICATIONS
6.3 MODBUS MEMORY MAP
Table 6–1: 489 MEMORY MAP (SHEET 14 OF 24)
ADDR NAME
2023 OVERVOLTAGE ALARM DELAY
2024 OVERVOLTAGE ALARM EVENTS
2025 OVERVOLTAGE TRIP
2026 ASSIGN TRIP RELAYS (1-4)
2027 OVERVOLTAGE TRIP PICKUP
2028 OVERVOLTAGE TRIP DELAY
2029 OVERVOLTAGE CURVE RESET RATE
202A OVERVOLTAGE CURVE ELEMENT
VOLTAGE ELEMENTS / VOLTS/HERTZ
2040 VOLTS/HERTZ ALARM
2041 ASSIGN ALARM RELAYS (2-5)
2042 VOLTS/HERTZ ALARM PICKUP
2043 VOLTS/HERTZ ALARM DELAY
2044 VOLTS/HERTZ ALARM EVENTS
2045 VOLTS/HERTZ TRIP
2046 ASSIGN TRIP RELAYS (1-4)
2047 VOLTS/HERTZ TRIP PICKUP
2048 VOLTS/HERTZ TRIP DELAY
2049 VOLTS/HERTZ CURVE RESET RATE
204A VOLTS/HERTZ TRIP ELEMENT
VOLTAGE ELEMENTS / PHASE REVERSAL
2060 PHASE REVERSAL TRIP
2061 ASSIGN TRIP RELAYS (1-4)
VOLTAGE ELEMENTS / UNDERFREQUENCY
2080 BLOCK UNDERFREQUENCY FROM ONLINE
2081 VOLTAGE LEVEL CUTOFF
2082 UNDERFREQUENCY ALARM
2083 ASSIGN ALARM RELAYS (2-5)
2084 UNDERFREQUENCY ALARM LEVEL
2085 UNDERFREQUENCY ALARM DELAY
2086 UNDERFREQUENCY ALARM EVENTS
2087 UNDERFREQUENCY TRIP
2088 ASSIGN TRIP RELAYS (1-4)
2089 UNDERFREQUENCY TRIP LEVEL1
208A UNDERFREQUENCY TRIP DELAY1
208B UNDERFREQUENCY TRIP LEVEL2
208C UNDERFREQUENCY TRIP DELAY2
VOLTAGE ELEMENTS / OVERFREQUENCY
20A0 BLOCK OVERFREQUENCY FROM ONLINE
20A1 VOLTAGE LEVEL CUTOFF
20A2 OVERFREQUENCY ALARM
20A3 ASSIGN ALARM RELAYS (2-5)
20A4 OVERFREQUENCY ALARM LEVEL
20A5 OVERFREQUENCY ALARM DELAY
20A6 OVERFREQUENCY ALARM EVENTS
20A7 OVERFREQUENCY TRIP
20A8 ASSIGN TRIP RELAYS (1-4)
20A9 OVERFREQUENCY TRIP LEVEL1
20AA OVERFREQUENCY TRIP DELAY1
20AB OVERFREQUENCY TRIP LEVEL2
20AC OVERFREQUENCY TRIP DELAY2
VOLTAGE ELEMENTS / NEUTRAL O/V (FUND)
20C0 NEUTRAL OVERVOLTAGE ALARM
20C1 ASSIGN ALARM RELAYS (2-5)
20C2 NEUTRAL O/V ALARM LEVEL
20C3 NEUTRAL OVERVOLTAGE ALARM DELAY
20C4 NEUTRAL OVERVOLTAGE ALARM EVENTS
20C5 NEUTRAL OVERVOLTAGE TRIP
20C6 ASSIGN TRIP RELAYS (1-4)
20C7 NEUTRAL O/V TRIP LEVEL
20C8 NEUTRAL OVERVOLTAGE TRIP DELAY
20C9 SUPERVISE WITH DIGITAL INPUT
20CA NEUTRAL O/V CURVE RESET RATE
20CB NEUTRAL O/V TRIP ELEMENT
1, 2, 3
See Table footnotes on page 6–33
GE Multilin
RANGE
1 to 1200
0 to 1
0 to 2
0 to 3
101 to 150
1 to 100
0 to 9999
0 to 1
STEP
1
1
1
1
1
1
1
1
UNITS
s
–
–
–
× Rated
s
s
–
FORMAT
F2
F105
F115
F50
F3
F2
F2
F208
DEFAULT
30
0
0
1
120
10
14
0
0 to 2
1 to 4
50 to 199
1 to 1500
0 to 1
0 to 2
0 to 3
50 to 199
1 to 1500
0 to 9999
0 to 3
1
1
1
1
1
1
1
1
1
1
1
–
–
× Nominal
s
–
–
–
× Nominal
s
s
–
F115
F50
F3
F2
F105
F115
F50
F3
F2
F2
F211
0
16
100
30
0
0
1
100
10
14
0
0 to 2
0 to 3
1
1
–
–
F115
F50
0
1
0 to 5
50 to 99
0 to 2
1 to 4
2000 to 6000
1 to 50000
0 to 1
0 to 2
0 to 3
2000 to 6000
1 to 50000
2000 to 6000
1 to 50000
1
1
1
1
1
1
1
1
1
1
1
1
1
s
× Rated
–
–
Hz
s
–
–
–
Hz
s
Hz
s
F1
F3
F115
F50
F3
F2
F105
F115
F50
F3
F2
F3
F2
1
50
0
16
5950
50
0
0
1
5950
600
5800
300
0 to 5
50 to 99
0 to 2
1 to 4
2501 to 7000
1 to 50000
0 to 1
0 to 2
0 to 3
2501 to 7000
1 to 50000
2501 to 7000
1 to 50000
1
1
1
1
1
1
1
1
1
1
1
1
1
s
× Rated
–
–
Hz
s
–
–
–
Hz
s
Hz
s
F1
F3
F115
F50
F3
F2
F105
F115
F50
F3
F2
F3
F2
1
50
0
16
6050
50
0
0
1
6050
600
6200
300
0 to 2
1 to 4
20 to 1000
1 to 1200
0 to 1
0 to 2
0 to 3
20 to 1000
1 to 1200
0 to 1
0 to 9999
0 to 1
1
1
1
1
1
1
1
1
1
1
1
1
–
–
V
s
–
–
–
V
s
–
s
–
F115
F50
F2
F2
F105
F115
F50
F2
F2
F103
F2
F208
0
16
30
10
0
0
1
50
10
0
0
1
489 Generator Management Relay
6
6-23
6.3 MODBUS MEMORY MAP
6 COMMUNICATIONS
Table 6–1: 489 MEMORY MAP (SHEET 15 OF 24)
6
ADDR NAME
VOLTAGE ELEMENTS / NEUTRAL U/V (3rd)
20E0 LOW POWER BLOCKING LEVEL
20E2 LOW VOLTAGE BLOCKING LEVEL
20E3 NEUTRAL UNDERVOLTAGE ALARM
20E4 ASSIGN ALARM RELAYS (2-5)
20E5 NEUTRAL U/V ALARM LEVEL
20E6 NEUTRAL UNDERVOLTAGE ALARM DELAY
20E7 NEUTRAL UNDERVOLTAGE ALARM EVENTS
20E8 NEUTRAL UNDERVOLTAGE TRIP
20E9 ASSIGN TRIP RELAYS (1-4)
20EA NEUTRAL U/V TRIP LEVEL
20EB NEUTRAL UNDERVOLTAGE TRIP DELAY
VOLTAGE ELEMENTS / LOSS OF EXCITATION
2100 ENABLE VOLTAGE SUPERVISION
2101 VOLTAGE LEVEL
2102 CIRCLE 1 TRIP
2103 ASSIGN CIRCLE 1 TRIP RELAYS (1-4)
2104 CIRCLE 1 DIAMETER
2105 CIRCLE 1 OFFSET
2106 CIRCLE 1 TRIP DELAY
2107 CIRCLE 2 TRIP
2108 ASSIGN CIRCLE 2 TRIP RELAYS (1-4)
2109 CIRCLE 2 DIAMETER
210A CIRCLE 2 OFFSET
210B CIRCLE 2 TRIP DELAY
VOLTAGE ELEMENTS / DISTANCE ELEMENT
2130 STEP UP TRANSFORMER SETUP
2131 FUSE FAILURE SUPERVISION
2132 ZONE 1 TRIP
2133 ASSIGN ZONE 1 TRIP RELAYS (1-4)
2134 ZONE 1 REACH
2135 ZONE 1 ANGLE
2136 ZONE 1 TRIP DELAY
2137 ZONE 2 TRIP
2138 ASSIGN ZONE 2 TRIP RELAYS (1-4)
2139 ZONE 2 REACH
213A ZONE 2 ANGLE
213B ZONE 2 TRIP DELAY
POWER ELEMENTS / REACTIVE POWER
2200 BLOCK Mvar ELEMENT FROM ONLINE
2201 REACTIVE POWER ALARM
2202 ASSIGN ALARM RELAYS (2-5)
2203 POSITIVE Mvar ALARM LEVEL 3
2205 NEGATIVE Mvar ALARM LEVEL 3
2207 NEGATIVE Mvar ALARM DELAY
2208 REACTIVE POWER ALARM EVENTS
2209 REACTIVE POWER TRIP
220A ASSIGN TRIP RELAYS (1-4)
220B POSITIVE Mvar TRIP LEVEL 3
220D NEGATIVE Mvar TRIP LEVEL 3
220F NEGATIVE Mvar TRIP DELAY
2210 POSITIVE Mvar TRIP DELAY
2211 POSITIVE Mvar ALARM DELAY
POWER ELEMENTS / REVERSE POWER
2240 BLOCK REVERSE POWER FROM ONLINE
2241 REVERSE POWER ALARM
2242 ASSIGN ALARM RELAYS (2-5)
2243 REVERSE POWER ALARM LEVEL
2245 REVERSE POWER ALARM DELAY
2246 REVERSE POWER ALARM EVENTS
2247 REVERSE POWER TRIP
2248 ASSIGN TRIP RELAYS (1-4)
2249 REVERSE POWER TRIP LEVEL
224B REVERSE POWER TRIP DELAY
1, 2, 3
See Table footnotes on page 6–33
6-24
RANGE
STEP
UNITS
FORMAT
DEFAULT
2 to 99
50 to 100
0 to 2
1 to 4
5 to 200
5 to 120
0 to 1
0 to 2
0 to 3
5 to 200
5 to 120
1
1
1
1
1
1
1
1
1
1
1
× Rated MW
× Rated
–
–
V
s
–
–
–
V
s
F14
F3
F115
F50
F2
F1
F105
F115
F50
F2
F1
5
75
0
16
5
30
0
0
1
10
30
0 to 1
70 to 100
0 to 2
0 to 3
25 to 3000
10 to 3000
1 to 100
0 to 2
0 to 3
25 to 3000
10 to 3000
1 to 100
1
1
1
1
1
1
1
1
1
1
1
1
–
× rated
–
–
Ωs
Ωs
s
–
–
Ωs
Ωs
s
F103
F3
F115
F50
F2
F2
F2
F115
F50
F2
F2
F2
0
70
0
1
250
25
50
0
1
350
25
50
0 to 1
0 to 1
0 to 2
0 to 3
1 to 5000
50 to 85
0 to 1500
0 to 2
0 to 3
1 to 5000
50 to 85
0 to 1500
1
1
1
1
1
1
1
1
1
1
1
1
–
–
–
–
Ωs
°
s
–
–
Ωs
°
s
F219
F105
F115
F50
F2
F1
F2
F115
F50
F2
F1
F2
0
0
0
1
100
75
4
0
1
100
75
20
0 to 5000
0 to 2
1 to 4
2 to 201
2 to 201
2 to 1200
0 to 1
0 to 2
0 to 3
2 to 201
2 to 201
2 to 1200
2 to 1200
2 to 1200
1
1
1
1
1
1
1
1
1
1
1
1
1
1
s
–
–
x rated
x rated
s
–
–
–
Mvar
Mvar
s
s
s
F1
F115
F50
F14
F14
F2
F105
F115
F50
F14
F14
F2
F2
F2
1
0
16
85
85
10
0
0
1
80
80
10
200
100
0 to 5000
0 to 2
1 to 4
2 to 99
2 to 1200
0 to 1
0 to 2
0 to 3
2 to 99
2 to 1200
1
1
1
1
1
1
1
1
1
1
s
–
–
× Rated
s
–
–
–
× Rated
s
F1
F115
F50
F14
F2
F105
F115
F50
F14
F2
1
0
16
5
100
0
0
1
5
200
489 Generator Management Relay
GE Multilin
6 COMMUNICATIONS
6.3 MODBUS MEMORY MAP
Table 6–1: 489 MEMORY MAP (SHEET 16 OF 24)
ADDR NAME
POWER ELEMENTS / LOW FORWARD POWER
2280 BLOCK LOW FWD POWER FROM ONLINE
2281 LOW FORWARD POWER ALARM
2282 ASSIGN ALARM RELAYS (2-5)
2283 LOW FWD POWER ALARM LEVEL
2285 LOW FWD POWER ALARM DELAY
2286 LOW FWD POWER ALARM EVENTS
2287 LOW FORWARD POWER TRIP
2288 ASSIGN TRIP RELAYS (1-4)
2289 LOW FWD POWER TRIP LEVEL
228B LOW FWD POWER TRIP DELAY
RTD TEMPERATURE / RTD TYPES
2400 STATOR RTD TYPE
2401 BEARING RTD TYPE
2402 AMBIENT RTD TYPE
2403 OTHER RTD TYPE
RTD TEMPERATURE / RTD #1
2420 RTD #1 APPLICATION
2421 RTD #1 ALARM
2422 ASSIGN ALARM RELAYS (2-5)
2423 RTD #1 ALARM TEMPERATURE
2424 RTD #1 ALARM EVENTS
2425 RTD #1 TRIP
2426 RTD #1 TRIP VOTING
2427 ASSIGN TRIP RELAYS (1-4)
2428 RTD #1 TRIP TEMPERATURE
2429 RTD #1 NAME
RTD TEMPERATURE / RTD #2
2460 RTD #2 APPLICATION
2461 RTD #2 ALARM
2462 ASSIGN ALARM RELAYS (2-5)
2463 RTD #2 ALARM TEMPERATURE
2464 RTD #2 ALARM EVENTS
2465 RTD #2 TRIP
2466 RTD #2 TRIP VOTING
2467 ASSIGN TRIP RELAYS (1-4)
2468 RTD #2 TRIP TEMPERATURE
2469 RTD #2 NAME
RTD TEMPERATURE / RTD #3
24A0 RTD #3 APPLICATION
24A1 RTD #3 ALARM
24A2 ASSIGN ALARM RELAYS (2-5)
24A3 RTD #3 ALARM TEMPERATURE
24A4 RTD #3 ALARM EVENTS
24A5 RTD #3 TRIP
24A6 RTD #3 TRIP VOTING
24A7 ASSIGN TRIP RELAYS (1-4)
24A8 RTD #3 TRIP TEMPERATURE
24A9 RTD #3 NAME
RTD TEMPERATURE / RTD #4
24E0 RTD #4 APPLICATION
24E1 RTD #4 ALARM
24E2 ASSIGN ALARM RELAYS (2-5)
24E3 RTD #4 ALARM TEMPERATURE
24E4 RTD #4 ALARM EVENTS
24E5 RTD #4 TRIP
24E6 RTD #4 TRIP VOTING
24E7 ASSIGN TRIP RELAYS (1-4)
24E8 RTD #4 TRIP TEMPERATURE
24E9 RTD #4 NAME
RTD TEMPERATURE / RTD #5
2520 RTD #5 APPLICATION
2521 RTD #5 ALARM
2522 ASSIGN ALARM RELAYS (2-5)
2523 RTD #5 ALARM TEMPERATURE
2524 RTD #5 ALARM EVENTS
1, 2, 3
See Table footnotes on page 6–33
GE Multilin
RANGE
STEP
UNITS
FORMAT
DEFAULT
0 to 15000
0 to 2
1 to 4
2 to 99
2 to 1200
0 to 1
0 to 2
0 to 3
2 to 99
2 to 1200
1
1
1
1
1
1
1
1
1
1
s
–
–
× Rated MW
s
–
–
–
× Rated MW
s
F1
F115
F50
F14
F2
F105
F115
F50
F14
F2
0
0
16
5
100
0
0
1
5
200
0 to 3
0 to 3
0 to 3
0 to 3
1
1
1
1
–
–
–
–
F120
F120
F120
F120
0
0
0
0
0 to 4
0 to 2
1 to 4
1 to 250
0 to 1
0 to 2
1 to 12
0 to 3
1 to 250
0 to 8
1
1
1
1
1
1
1
1
1
1
–
–
–
°C
–
–
–
–
°C
–
F121
F115
F50
F1
F105
F115
F122
F50
F1
F22
1
0
16
130
0
0
1
1
155
_
0 to 4
0 to 2
1 to 4
1 to 250
0 to 1
0 to 2
1 to 12
0 to 3
1 to 250
0 to 8
1
1
1
1
1
1
1
1
1
1
–
–
–
°C
–
–
–
–
°C
–
F121
F115
F50
F1
F105
F115
F122
F50
F1
F22
1
0
16
130
0
0
2
1
155
_
0 to 4
0 to 2
1 to 4
1 to 250
0 to 1
0 to 2
1 to 12
0 to 3
1 to 250
0 to 8
1
1
1
1
1
1
1
1
1
1
–
–
–
°C
–
–
–
–
°C
–
F121
F115
F50
F1
F105
F115
F122
F50
F1
F22
1
0
16
130
0
0
3
1
155
_
0 to 4
0 to 2
1 to 4
1 to 250
0 to 1
0 to 2
1 to 12
0 to 3
1 to 250
0 to 8
1
1
1
1
1
1
1
1
1
1
–
–
–
°C
–
–
–
–
°C
–
F121
F115
F50
F1
F105
F115
F122
F50
F1
F22
1
0
16
130
0
0
4
1
155
_
0 to 4
0 to 2
1 to 4
1 to 250
0 to 1
1
1
1
1
1
–
–
–
°C
–
F121
F115
F50
F1
F105
1
0
16
130
0
489 Generator Management Relay
6
6-25
6.3 MODBUS MEMORY MAP
6 COMMUNICATIONS
Table 6–1: 489 MEMORY MAP (SHEET 17 OF 24)
6
ADDR NAME
2525 RTD #5 TRIP
2526 RTD #5 TRIP VOTING
2527 ASSIGN TRIP RELAYS (1-4)
2528 RTD #5 TRIP TEMPERATURE
2529 RTD #5 NAME
RTD TEMPERATURE / RTD #6
2560 RTD #6 APPLICATION
2561 RTD #6 ALARM
2562 ASSIGN ALARM RELAYS (2-5)
2563 RTD #6 ALARM TEMPERATURE
2564 RTD #6 ALARM EVENTS
2565 RTD #6 TRIP
2566 RTD #6 TRIP VOTING
2567 ASSIGN TRIP RELAYS (1-4)
2568 RTD #6 TRIP TEMPERATURE
2569 RTD #6 NAME
RTD TEMPERATURE / RTD #7
25A0 RTD #7 APPLICATION
25A1 RTD #7 ALARM
25A2 ASSIGN ALARM RELAYS (2-5)
25A3 RTD #7 ALARM TEMPERATURE
25A4 RTD #7 ALARM EVENTS
25A5 RTD #7 TRIP
25A6 RTD #7 TRIP VOTING
25A7 ASSIGN TRIP RELAYS (1-4)
25A8 RTD #7 TRIP TEMPERATURE
25A9 RTD #7 NAME
RTD TEMPERATURE / RTD #8
25E0 RTD #8 APPLICATION
25E1 RTD #8 ALARM
25E2 ASSIGN ALARM RELAYS (2-5)
25E3 RTD #8 ALARM TEMPERATURE
25E4 RTD #8 ALARM EVENTS
25E5 RTD #8 TRIP
25E6 RTD #8 TRIP VOTING
25E7 ASSIGN TRIP RELAYS (1-4)
25E8 RTD #8 TRIP TEMPERATURE
25E9 RTD #8 NAME
RTD TEMPERATURE / RTD #9
2620 RTD #9 APPLICATION
2621 RTD #9 ALARM
2622 ASSIGN ALARM RELAYS (2-5)
2623 RTD #9 ALARM TEMPERATURE
2624 RTD #9 ALARM EVENTS
2625 RTD #9 TRIP
2626 RTD #9 TRIP VOTING
2627 ASSIGN TRIP RELAYS (1-4)
2628 RTD #9 TRIP TEMPERATURE
2629 RTD #9 NAME
RTD TEMPERATURE / RTD #10
2660 RTD #10 APPLICATION
2661 RTD #10 ALARM
2662 ASSIGN ALARM RELAYS (2-5)
2663 RTD #10 ALARM TEMPERATURE
2664 RTD #10 ALARM EVENTS
2665 RTD #10 TRIP
2666 RTD #10 TRIP VOTING
2667 ASSIGN TRIP RELAYS (1-4)
2668 RTD #10 TRIP TEMPERATURE
2669 RTD #10 NAME
RTD TEMPERATURE / RTD #11
26A0 RTD #11 APPLICATION
26A1 RTD #11 ALARM
26A2 ASSIGN ALARM RELAYS (2-5)
26A3 RTD #11 ALARM TEMPERATURE
26A4 RTD #11 ALARM EVENTS
1, 2, 3
See Table footnotes on page 6–33
6-26
RANGE
0 to 2
1 to 12
0 to 3
1 to 250
0 to 8
STEP
1
1
1
1
1
UNITS
–
–
–
°C
–
FORMAT
F115
F122
F50
F1
F22
DEFAULT
0
5
1
155
_
0 to 4
0 to 2
1 to 4
1 to 250
0 to 1
0 to 2
1 to 12
0 to 3
1 to 250
0 to 8
1
1
1
1
1
1
1
1
1
1
–
–
–
°C
–
–
–
–
°C
–
F121
F115
F50
F1
F105
F115
F122
F50
F1
F22
1
0
16
130
0
0
6
1
155
_
0 to 4
0 to 2
1 to 4
1 to 250
0 to 1
0 to 2
1 to 12
0 to 3
1 to 250
0 to 8
1
1
1
1
1
1
1
1
1
1
–
–
–
°C
–
–
–
–
°C
–
F121
F115
F50
F1
F105
F115
F122
F50
F1
F22
2
0
16
80
0
0
7
1
90
_
0 to 4
0 to 2
1 to 4
1 to 250
0 to 1
0 to 2
1 to 12
0 to 3
1 to 250
0 to 8
1
1
1
1
1
1
1
1
1
1
–
–
–
°C
–
–
–
–
°C
–
F121
F115
F50
F1
F105
F115
F122
F50
F1
F22
2
0
16
80
0
0
8
1
90
_
0 to 4
0 to 2
1 to 4
1 to 250
0 to 1
0 to 2
1 to 12
0 to 3
1 to 250
0 to 8
1
1
1
1
1
1
1
1
1
1
–
–
–
°C
–
–
–
–
°C
–
F121
F115
F50
F1
F105
F115
F122
F50
F1
F22
2
0
16
80
0
0
9
1
90
_
0 to 4
0 to 2
1 to 4
1 to 250
0 to 1
0 to 2
1 to 12
0 to 3
1 to 250
0 to 8
1
1
1
1
1
1
1
1
1
1
–
–
–
°C
–
–
–
–
°C
–
F121
F115
F50
F1
F105
F115
F122
F50
F1
F22
2
0
16
80
0
0
10
1
90
_
0 to 4
0 to 2
1 to 4
1 to 250
0 to 1
1
1
1
1
1
–
–
–
°C
–
F121
F115
F50
F1
F105
4
0
16
80
0
489 Generator Management Relay
GE Multilin
6 COMMUNICATIONS
6.3 MODBUS MEMORY MAP
Table 6–1: 489 MEMORY MAP (SHEET 18 OF 24)
ADDR NAME
26A5 RTD #11 TRIP
26A6 RTD #11 TRIP VOTING
26A7 ASSIGN TRIP RELAYS (1-4)
26A8 RTD #11 TRIP TEMPERATURE
26A9 RTD #11 NAME
RTD TEMPERATURE / RTD #12
26E0 RTD #12 APPLICATION
26E1 RTD #12 ALARM
26E2 ASSIGN ALARM RELAYS (2-5)
26E3 RTD #12 ALARM TEMPERATURE
26E4 RTD #12 ALARM EVENTS
26E5 RTD #12 TRIP
26E6 RTD #12 TRIP VOTING
26E7 ASSIGN TRIP RELAYS (1-4)
26E8 RTD #12 TRIP TEMPERATURE
26E9 RTD #12 NAME
RTD TEMPERATURE / OPEN RTD SENSOR
2720 OPEN RTD SENSOR ALARM
2721 ASSIGN ALARM RELAYS (2-5)
2722 OPEN RTD SENSOR ALARM EVENTS
RTD TEMPERATURE / RTD SHORT/LOW TEMP
2740 RTD SHORT/LOW TEMP ALARM
2741 ASSIGN ALARM RELAYS (2-5)
2742 RTD SHORT/LOW TEMP ALARM EVENTS
THERMAL MODEL / MODEL SETUP
2800 ENABLE THERMAL MODEL
2801 OVERLOAD PICKUP LEVEL
2802 UNBALANCE BIAS K FACTOR
2803 COOL TIME CONSTANT ONLINE
2804 COOL TIME CONSTANT OFFLINE
2805 HOT/COLD SAFE STALL RATIO
2806 ENABLE RTD BIASING
2807 RTD BIAS MINIMUM
2808 RTD BIAS CENTER POINT
2809 RTD BIAS MAXIMUM
280A SELECT CURVE STYLE
280B STANDARD OVERLOAD CURVE NUMBER
280C TIME TO TRIP AT 1.01 × FLA
280E TIME TO TRIP AT 1.05 × FLA
2810 TIME TO TRIP AT 1.10 × FLA
2812 TIME TO TRIP AT 1.20 × FLA
2814 TIME TO TRIP AT 1.30 × FLA
2816 TIME TO TRIP AT 1.40 × FLA
2818 TIME TO TRIP AT 1.50 × FLA
281A TIME TO TRIP AT 1.75 × FLA
281C TIME TO TRIP AT 2.00 × FLA
281E TIME TO TRIP AT 2.25 × FLA
2820 TIME TO TRIP AT 2.50 × FLA
2822 TIME TO TRIP AT 2.75 × FLA
2824 TIME TO TRIP AT 3.00 × FLA
2826 TIME TO TRIP AT 3.25 × FLA
2828 TIME TO TRIP AT 3.50 × FLA
282A TIME TO TRIP AT 3.75 × FLA
282C TIME TO TRIP AT 4.00 × FLA
282E TIME TO TRIP AT 4.25 × FLA
2830 TIME TO TRIP AT 4.50 × FLA
2832 TIME TO TRIP AT 4.75 × FLA
2834 TIME TO TRIP AT 5.00 × FLA
2836 TIME TO TRIP AT 5.50 × FLA
2838 TIME TO TRIP AT 6.00 × FLA
283A TIME TO TRIP AT 6.50 × FLA
283C TIME TO TRIP AT 7.00 × FLA
283E TIME TO TRIP AT 7.50 × FLA
2840 TIME TO TRIP AT 8.00 × FLA
2842 TIME TO TRIP AT 10.0 × FLA
2844 TIME TO TRIP AT 15.0 × FLA
1, 2, 3
See Table footnotes on page 6–33
GE Multilin
RANGE
0 to 2
1 to 12
0 to 3
1 to 250
0 to 8
STEP
1
1
1
1
1
UNITS
–
–
–
°C
–
FORMAT
F115
F122
F50
F1
F22
DEFAULT
0
11
1
90
_
0 to 4
0 to 2
1 to 4
1 to 250
0 to 1
0 to 2
1 to 12
0 to 3
1 to 250
0 to 8
1
1
1
1
1
1
1
1
1
1
–
–
–
°C
–
–
–
–
°C
–
F121
F115
F50
F1
F105
F115
F122
F50
F1
F22
3
0
16
60
0
0
12
1
80
_
0 to 2
1 to 4
0 to 1
1
1
1
–
–
–
F115
F50
F105
0
16
0
0 to 2
1 to 4
0 to 1
1
1
1
–
–
–
F115
F50
F105
0
16
0
0 to 1
101 to 125
0 to 12
0 to 500
0 to 500
1 to 100
0 to 1
0 to 250
0 to 250
0 to 250
0 to 2
1 to 15
5 to 999999
5 to 999999
5 to 999999
5 to 999999
5 to 999999
5 to 999999
5 to 999999
5 to 999999
5 to 999999
5 to 999999
5 to 999999
5 to 999999
5 to 999999
5 to 999999
5 to 999999
5 to 999999
5 to 999999
5 to 999999
5 to 999999
5 to 999999
5 to 999999
5 to 999999
5 to 999999
5 to 999999
5 to 999999
5 to 999999
5 to 999999
5 to 999999
5 to 999999
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
–
× FLA
–
min
min
–
–
°C
°C
°C
–
–
s
s
s
s
s
s
s
s
s
s
s
s
s
s
s
s
s
s
s
s
s
s
s
s
s
s
s
s
s
F103
F3
F1
F1
F1
F3
F103
F1
F1
F1
F142
F1
F10
F10
F10
F10
F10
F10
F10
F10
F10
F10
F10
F10
F10
F10
F10
F10
F10
F10
F10
F10
F10
F10
F10
F10
F10
F10
F10
F10
F10
0
101
0
15
30
100
0
40
130
155
0
4
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
489 Generator Management Relay
6
6-27
6.3 MODBUS MEMORY MAP
6 COMMUNICATIONS
Table 6–1: 489 MEMORY MAP (SHEET 19 OF 24)
6
ADDR NAME
2846 TIME TO TRIP AT 20.0 × FLA
2848 MINIMUM ALLOWABLE VOLTAGE
2849 STALL CURRENT @ MIN VOLTAGE
284A SAFE STALL TIME @ MIN VOLTAGE
284B ACCEL. INTERSECT @ MIN VOLT
284C STALL CURRENT @ 100% VOLTAGE
284D SAFE STALL TIME @ 100% VOLTAGE
284E ACCEL. INTERSECT @ 100% VOLT
THERMAL MODEL / THERMAL ELEMENTS
2900 THERMAL MODEL ALARM
2901 ASSIGN ALARM RELAYS (2-5)
2902 THERMAL ALARM LEVEL
2903 THERMAL MODEL ALARM EVENTS
2904 THERMAL MODEL TRIP
2905 ASSIGN TRIP RELAYS (1-4)
MONITORING / TRIP COUNTER
2A00 TRIP COUNTER ALARM
2A01 ASSIGN ALARM RELAYS (2-5)
2A02 TRIP COUNTER ALARM LEVEL
2A03 TRIP COUNTER ALARM EVENTS
MONITORING / BREAKER FAILURE
2A20 BREAKER FAILURE ALARM
2A21 ASSIGN ALARM RELAYS (2-5)
2A22 BREAKER FAILURE LEVEL
2A23 BREAKER FAILURE DELAY
2A24 BREAKER FAILURE ALARM EVENTS
MONITORING / TRIP COIL MONITOR
2A30 TRIP COIL MONITOR ALARM
2A31 ASSIGN ALARM RELAYS (2-5)
2A32 TRIP COIL MONITOR ALARM EVENTS
MONITORING / VT FUSE FAILURE
2A50 VT FUSE FAILURE ALARM
2A51 ASSIGN ALARM RELAYS (2-5)
2A52 VT FUSE FAILURE ALARM EVENTS
MONITORING / CURRENT DEMAND
2A60 CURRENT DEMAND PERIOD
2A61 CURRENT DEMAND ALARM
2A62 ASSIGN ALARM RELAYS (2-5)
2A63 CURRENT DEMAND LIMIT
2A65 CURRENT DEMAND ALARM EVENTS
MONITORING / MW DEMAND
2A70 MW DEMAND PERIOD
2A71 MW DEMAND ALARM
2A72 ASSIGN ALARM RELAYS (2-5)
2A73 MW DEMAND LIMIT
2A75 MW DEMAND ALARM EVENTS
MONITORING / Mvar DEMAND
2A80 Mar DEMAND PERIOD
2A81 Mar DEMAND ALARM
2A82 ASSIGN ALARM RELAYS (2-5)
2A83 Mar DEMAND LIMIT
2A85 Mar DEMAND ALARM EVENTS
MONITORING / MVA DEMAND
2A90 MVA DEMAND PERIOD
2A91 MVA DEMAND ALARM
2A92 ASSIGN ALARM RELAYS (2-5)
2A93 MVA DEMAND LIMIT
2A95 MVA DEMAND ALARM EVENTS
MONITORING / PULSE OUTPUT
2AB0 POS. kWh PULSE OUT RELAYS (2-5)
2AB1 POS. kWh PULSE OUT INTERVAL
2AB2 POS. kvarh PULSE OUT RELAYS (2-5)
2AB3 POS. kvarh PULSE OUT INTERVAL
2AB4 NEG. kvarh PULSE OUT RELAYS (2-5)
2AB5 NEG. kvarh PULSE OUT INTERVAL
2AB6 PULSE WIDTH
1, 2, 3
See Table footnotes on page 6–33
6-28
RANGE
5 to 999999
70 to 95
200 to 1500
5 to 9999
200 to 1500
200 to 1500
5 to 9999
200 to 1500
STEP
1
1
1
1
1
1
1
1
UNITS
s
%
× FLA
s
× FLA
× FLA
s
× FLA
FORMAT
F10
F1
F3
F2
F3
F3
F2
F3
DEFAULT
5
80
480
200
380
600
100
500
0 to 2
1 to 4
10 to 100
0 to 1
0 to 2
0 to 3
1
1
1
1
1
1
–
–
%Used
–
–
–
F115
F50
F1
F105
F115
F50
0
16
75
0
0
1
0 to 2
1 to 4
1 to 50000
0 to 1
1
1
1
1
–
–
Trips
–
F115
F50
F1
F105
0
16
25
0
0 to 2
1 to 4
5 to 2000
10 to 1000
0 to 1
1
1
1
10
1
–
–
× CT
ms
–
F115
F50
F3
F1
F105
0
16
100
100
0
0 to 2
1 to 4
0 to 1
1
1
1
–
–
–
F115
F50
F105
0
16
0
0 to 2
1 to 4
0 to 1
1
1
1
–
–
–
F115
F50
F105
0
16
0
5 to 90
0 to 2
1 to 4
10 to 2000
0 to 1
1
1
1
1
1
min
A
A
× FLA
A
F1
F115
F50
F14
F105
15
0
16
125
0
5 to 90
0 to 2
1 to 4
10 to 200
0 to 1
1
1
1
1
1
min
–
–
× Rated
–
F1
F115
F50
F14
F105
15
0
16
125
0
5 to 90
0 to 2
1 to 4
10 to 200
0 to 1
1
1
1
1
1
min
–
–
× Rated
–
F1
F115
F50
F14
F105
15
0
16
125
0
5 to 90
0 to 2
1 to 4
10 to 200
0 to 1
1
1
1
1
1
min
–
–
× Rated
–
F1
F115
F50
F14
F105
15
0
16
125
0
1 to 4
1 to 50000
1 to 4
1 to 50000
1 to 4
1 to 50000
200 to 1000
1
1
1
1
1
1
1
–
–
–
–
–
–
–
F50
F1
F50
F1
F50
F1
F1
0
10
0
10
0
10
200
489 Generator Management Relay
GE Multilin
6 COMMUNICATIONS
6.3 MODBUS MEMORY MAP
Table 6–1: 489 MEMORY MAP (SHEET 20 OF 24)
ADDR NAME
MONITORING / RUNNING HOUR SETUP
2AC0 INITIAL GEN. RUNNING HOUR
2AC2 GEN. RUNNING HOUR ALARM
2AC3 ASSIGN ALARM RELAYS (2-5)
2AC4 GEN. RUNNING HOUR LIMIT
2AC6 RESERVED
ANALOG I/O / ANALOG OUTPUT 1
2B00 ANALOG OUTPUT 1
ANALOG I/O / ANALOG OUTPUT 2
2B01 ANALOG OUTPUT 2
ANALOG I/O / ANALOG OUTPUT 3
2B02 ANALOG OUTPUT 3
ANALOG I/O / ANALOG OUTPUT 4
2B03 ANALOG OUTPUT 4
ANALOG I/O / ANALOG OUTPUTS
2B04 IA OUTPUT CURRENT MIN
2B05 IA OUTPUT CURRENT MAX
2B06 IB OUTPUT CURRENT MIN
2B07 IB OUTPUT CURRENT MAX
2B08 IC OUTPUT CURRENT MIN
2B09 IC OUTPUT CURRENT MAX
2B0A AVG OUTPUT CURRENT MIN
2B0B AVG OUTPUT CURRENT MAX
2B0C NEG. SEQ. CURRENT MIN
2B0D NEG. SEQ. CURRENT MAX
2B0E AVERAGED GEN. LOAD MIN
2B0F AVERAGED GEN. LOAD MAX
2B10 HOTTEST STATOR RTD MIN
2B11 HOTTEST STATOR RTD MAX
2B12 HOTTEST BEARING RTD MIN
2B13 HOTTEST BEARING RTD MAX
2B14 AMBIENT RTD MIN
2B15 AMBIENT RTD MAX
2B16 RTD #1 MIN
2B17 RTD #1 MAX
2B18 RTD #2 MIN
2B19 RTD #2 MAX
2B1A RTD #3 MIN
2B1B RTD #3 MAX
2B1C RTD #4 MIN
2B1D RTD #4 MAX
2B1E RTD #5 MIN
2B1F RTD #5 MAX
2B20 RTD #6 MIN
2B21 RTD #6 MAX
2B22 RTD #7 MIN
2B23 RTD #7 MAX
2B24 RTD #8 MIN
2B25 RTD #8 MAX
2B26 RTD #9 MIN
2B27 RTD #9 MAX
2B28 RTD #10 MIN
2B29 RTD #10 MAX
2B2A RTD #11 MIN
2B2B RTD #11 MAX
2B2C RTD #12 MIN
2B2D RTD #12 MAX
2B2E AB VOLTAGE MIN
2B2F AB VOLTAGE MAX
2B30 BC VOLTAGE MIN
2B31 BC VOLTAGE MAX
2B32 CA VOLTAGE MIN
2B33 CA VOLTAGE MAX
2B34 AVERAGE VOLTAGE MIN
2B35 AVERAGE VOLTAGE MAX
2B36 VOLTS/HERTZ MIN
1, 2, 3
See Table footnotes on page 6–33
GE Multilin
RANGE
STEP
UNITS
FORMAT
DEFAULT
0 to 999999
0 to 2
1 to 4
1 to 1000000
1
1
1
1
h
–
–
h
F12
F115
F50
F12
0
0
16
1000
0 to 42
1
–
F127
0
0 to 42
1
–
F127
0
0 to 42
1
–
F127
0
0 to 42
1
–
F127
0
0 to 2000
0 to 2000
0 to 2000
0 to 2000
0 to 2000
0 to 2000
0 to 2000
0 to 2000
0 to 2000
0 to 2000
0 to 2000
0 to 2000
–50 to 250
–50 to 250
–50 to 250
–50 to 250
–50 to 250
–50 to 250
–50 to 250
–50 to 250
–50 to 250
–50 to 250
–50 to 250
–50 to 250
–50 to 250
–50 to 250
–50 to 250
–50 to 250
–50 to 250
–50 to 250
–50 to 250
–50 to 250
–50 to 250
–50 to 250
–50 to 250
–50 to 250
–50 to 250
–50 to 250
–50 to 250
–50 to 250
–50 to 250
–50 to 250
0 to 150
0 to 150
0 to 150
0 to 150
0 to 150
0 to 150
0 to 150
0 to 150
0 to 200
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
× FLA
× FLA
× FLA
× FLA
× FLA
× FLA
× FLA
× FLA
%FLA
%FLA
× FLA
× FLA
°C
°C
°C
°C
°C
°C
°C
°C
°C
°C
°C
°C
°C
°C
°C
°C
°C
°C
°C
°C
°C
°C
°C
°C
°C
°C
°C
°C
°C
°C
× Rated
× Rated
× Rated
× Rated
× Rated
× Rated
× Rated
× Rated
× Rated
F3
F3
F3
F3
F3
F3
F3
F3
F1
F1
F3
F3
F4
F4
F4
F4
F4
F4
F4
F4
F4
F4
F4
F4
F4
F4
F4
F4
F4
F4
F4
F4
F4
F4
F4
F4
F4
F4
F4
F4
F4
F4
F3
F3
F3
F3
F3
F3
F3
F3
F3
0
125
0
125
0
125
0
125
0
100
0
125
0
200
0
200
0
70
0
200
0
200
0
200
0
200
0
200
0
200
0
200
0
200
0
200
0
200
0
200
0
200
0
125
0
125
0
125
0
125
0
489 Generator Management Relay
6
6-29
6.3 MODBUS MEMORY MAP
6 COMMUNICATIONS
Table 6–1: 489 MEMORY MAP (SHEET 21 OF 24)
6
ADDR NAME
2B37 VOLTS/HERTZ MAX
2B38 FREQUENCY MIN
2B39 FREQUENCY MAX
2B3C POWER FACTOR MIN
2B3D POWER FACTOR MAX
2B3E REACTIVE POWER MIN
2B3F REACTIVE POWER MAX
2B40 REAL POWER (MW) MIN
2B41 REAL POWER (MW) MAX
2B42 APPARENT POWER MIN
2B43 APPARENT POWER MAX
2B44 ANALOG INPUT 1 MIN
2B46 ANALOG INPUT 1 MAX
2B48 ANALOG INPUT 2 MIN
2B4A ANALOG INPUT 2 MAX
2B4C ANALOG INPUT 3 MIN
2B4E ANALOG INPUT 3 MAX
2B50 ANALOG INPUT 4 MIN
2B52 ANALOG INPUT 4 MAX
2B54 TACHOMETER MIN
2B55 TACHOMETER MAX
2B56 THERM. CAPACITY USED MIN
2B57 THERM. CAPACITY USED MAX
2B58 NEUTRAL VOLT THIRD MIN
2B5A NEUTRAL VOLT THIRD MAX
2B5C CURRENT DEMAND MIN
2B5D CURRENT DEMAND MAX
2B5E Mar DEMAND MIN
2B5F Mar DEMAND MAX
2B60 MW DEMAND MIN
2B61 MW DEMAND MAX
2B62 MVA DEMAND MIN
2B63 MVA DEMAND MAX
ANALOG I/O / ANALOG INPUT 1
2C00 ANALOG INPUT1
2C05 ANALOG INPUT1 UNITS
2C08 ANALOG INPUT1 MINIMUM
2C0A ANALOG INPUT1 MAXIMUM
2C0C BLOCK ANALOG INPUT1 FROM ONLINE
2C0D ANALOG INPUT1 ALARM
2C0E ASSIGN ALARM RELAYS (2-5)
2C0F ANALOG INPUT1 ALARM LEVEL
2C11 ANALOG INPUT1 ALARM PICKUP
2C12 ANALOG INPUT1 ALARM DELAY
2C13 ANALOG INPUT1 ALARM EVENTS
2C14 ANALOG INPUT1 TRIP
2C15 ASSIGN TRIP RELAYS (1-4)
2C16 ANALOG INPUT1 TRIP LEVEL
2C18 ANALOG INPUT1 TRIP PICKUP
2C19 ANALOG INPUT1 TRIP DELAY
2C1A ANALOG INPUT1 NAME
ANALOG I/O / ANALOG INPUT 2
2C40 ANALOG INPUT2
2C45 ANALOG INPUT2 UNITS
2C48 ANALOG INPUT2 MINIMUM
2C4A ANALOG INPUT2 MAXIMUM
2C4C BLOCK ANALOG INPUT2 FROM ONLINE
2C4D ANALOG INPUT2 ALARM
2C4E ASSIGN ALARM RELAYS (2-5)
2C4F ANALOG INPUT2 ALARM LEVEL
2C51 ANALOG INPUT2 ALARM PICKUP
2C52 ANALOG INPUT2 ALARM DELAY
2C53 ANALOG INPUT2 ALARM EVENTS
2C54 ANALOG INPUT2 TRIP
2C55 ASSIGN TRIP RELAYS (1-4)
2C56 ANALOG INPUT2 TRIP LEVEL
1, 2, 3
See Table footnotes on page 6–33
6-30
RANGE
0 to 200
0 to 9000
0 to 9000
–99 to 100
–99 to 100
–200 to 200
–200 to 200
–200 to 200
–200 to 200
0 to 200
0 to 200
–50000 to 50000
–50000 to 50000
–50000 to 50000
–50000 to 50000
–50000 to 50000
–50000 to 50000
–50000 to 50000
–50000 to 50000
0 to 7200
0 to 7200
0 to 100
0 to 100
0 to 250000
0 to 250000
0 to 2000
0 to 2000
0 to 200
0 to 200
0 to 200
0 to 200
0 to 200
0 to 200
STEP
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
UNITS
× Rated
Hz
Hz
–
–
× Rated
× Rated
× Rated
× Rated
× Rated
× Rated
Units
Units
Units
Units
Units
Units
Units
Units
RPM
RPM
%
%
Volts
Volts
× FLA
× FLA
× Rated
× Rated
× Rated
× Rated
× Rated
× Rated
FORMAT
F3
F3
F3
F6
F6
F6
F6
F6
F6
F3
F3
F12
F12
F12
F12
F12
F12
F12
F12
F1
F1
F1
F1
F10
F10
F3
F3
F3
F3
F3
F3
F3
F3
DEFAULT
150
5900
6100
80
–80
0
125
0
125
0
125
0
50000
0
50000
0
50000
0
50000
3500
3700
0
100
0
450
0
125
0
125
0
125
0
125
0 to 3
0 to 6
–50000 to 50000
–50000 to 50000
0 to 5000
0 to 2
1 to 4
–50000 to 50000
0 to 1
1 to 3000
0 to 1
0 to 2
0 to 3
–50000 to 50000
0 to 1
1 to 3000
0 to 12
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
–
–
Units
Units
s
–
–
Units
–
s
–
–
–
Units
–
s
–
F129
F22
F12
F12
F1
F115
F50
F12
F130
F2
F105
F115
F50
F12
F130
F2
F22
0
_
0
100
0
0
16
10
0
1
0
0
1
20
0
1
_
0 to 3
0 to 6
–50000 to 50000
–50000 to 50000
0 to 5000
0 to 2
1 to 4
–50000 to 50000
0 to 1
1 to 3000
0 to 1
0 to 2
0 to 3
–50000 to 50000
1
1
1
1
1
1
1
1
1
1
1
1
1
1
–
–
Units
Units
s
–
–
Units
–
s
–
–
–
Units
F129
F22
F12
F12
F1
F115
F50
F12
F130
F2
F105
F115
F50
F12
0
_
0
100
0
0
16
10
0
1
0
0
1
20
489 Generator Management Relay
GE Multilin
6 COMMUNICATIONS
6.3 MODBUS MEMORY MAP
Table 6–1: 489 MEMORY MAP (SHEET 22 OF 24)
ADDR NAME
2C58 ANALOG INPUT2 TRIP PICKUP
2C59 ANALOG INPUT2 TRIP DELAY
2C5A ANALOG INPUT2 NAME
ANALOG I/O / ANALOG INPUT 3
2C80 ANALOG INPUT3
2C85 ANALOG INPUT3 UNITS
2C88 ANALOG INPUT3 MINIMUM
2C8A ANALOG INPUT3 MAXIMUM
2C8C BLOCK ANALOG INPUT3 FROM ONLINE
2C8D ANALOG INPUT3 ALARM
2C8E ASSIGN ALARM RELAYS (2-5)
2C8F ANALOG INPUT3 ALARM LEVEL
2C91 ANALOG INPUT3 ALARM PICKUP
2C92 ANALOG INPUT3 ALARM DELAY
2C93 ANALOG INPUT3 ALARM EVENTS
2C94 ANALOG INPUT3 TRIP
2C95 ASSIGN TRIP RELAYS (1-4)
2C96 ANALOG INPUT3 TRIP LEVEL
2C98 ANALOG INPUT3 TRIP PICKUP
2C99 ANALOG INPUT3 TRIP DELAY
2C9A ANALOG INPUT3 NAME
ANALOG I/O / ANALOG INPUT 4
2CC0 ANALOG INPUT4
2CC5 ANALOG INPUT4 UNITS
2CC8 ANALOG INPUT4 MINIMUM
2CCA ANALOG INPUT4 MAXIMUM
2CCC BLOCK ANALOG INPUT4 FROM ONLINE
2CCD ANALOG INPUT4 ALARM
2CCE ASSIGN ALARM RELAYS (2-5)
2CCF ANALOG INPUT4 ALARM LEVEL
2CD1 ANALOG INPUT4 ALARM PICKUP
2CD2 ANALOG INPUT4 ALARM DELAY
2CD3 ANALOG INPUT4 ALARM EVENTS
2CD4 ANALOG INPUT4 TRIP
2CD5 ASSIGN TRIP RELAYS (1-4)
2CD6 ANALOG INPUT4 TRIP LEVEL
2CD8 ANALOG INPUT4 TRIP PICKUP
2CD9 ANALOG INPUT4 TRIP DELAY
2CDA ANALOG INPUT4 NAME
489 TESTING / SIMULATION MODE
2D00 SIMULATION MODE
2D01 PRE-FAULT TO FAULT TIME DELAY
489 TESTING / PRE-FAULT SETUP
2D20 PRE-FAULT Iphase OUTPUT
2D21 PRE-FAULT VOLTAGES PHASE-N
2D22 PRE-FAULT CURRENT LAGS VOLTAGE
2D23 PRE-FAULT Iphase NEUTRAL
2D24 PRE-FAULT CURRENT GROUND
2D25 PRE-FAULT VOLTAGE NEUTRAL
2D26 PRE-FAULT STATOR RTD TEMP
2D27 PRE-FAULT BEARING RTD TEMP
2D28 PRE-FAULT OTHER RTD TEMP
2D29 PRE-FAULT AMBIENT RTD TEMP
2D2A PRE-FAULT SYSTEM FREQUENCY
2D2B PRE-FAULT ANALOG INPUT 1
2D2C PRE-FAULT ANALOG INPUT 2
2D2D PRE-FAULT ANALOG INPUT 3
2D2E PRE-FAULT ANALOG INPUT 4
2D4C PRE-FAULT STATOR RTD TEMP
2D4D PRE-FAULT BEARING RTD TEMP
2D4E PRE-FAULT OTHER RTD TEMP
2D4F PRE-FAULT AMBIENT RTD TEMP
489 TESTING / FAULT SETUP
2D80 FAULT Iphase OUTPUT
2D81 FAULT VOLTAGES PHASE-N
2D82 FAULT CURRENT LAGS VOLTAGE
1, 2, 3
See Table footnotes on page 6–33
GE Multilin
RANGE
0 to 1
1 to 3000
0 to 12
STEP
1
1
1
UNITS
–
s
–
FORMAT
F130
F2
F22
DEFAULT
0
1
_
0 to 3
0 to 6
–50000 to 50000
–50000 to 50000
0 to 5000
0 to 2
1 to 4
–50000 to 50000
0 to 1
1 to 3000
0 to 1
0 to 2
0 to 3
–50000 to 50000
0 to 1
1 to 3000
0 to 12
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
–
–
Units
Units
s
–
–
Units
–
s
–
–
–
Units
–
s
–
F129
F22
F12
F12
F1
F115
F50
F12
F130
F2
F105
F115
F50
F12
F130
F2
F22
0
_
0
100
0
0
16
10
0
1
0
0
1
20
0
1
_
0 to 3
0 to 6
–50000 to 50000
–50000 to 50000
0 to 5000
0 to 2
1 to 4
–50000 to 50000
0 to 1
1 to 3000
0 to 1
0 to 2
0 to 3
–50000 to 50000
0 to 1
1 to 3000
0 to 12
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
–
–
Units
Units
s
–
–
Units
–
s
–
–
–
Units
–
s
–
F129
F22
F12
F12
F1
F115
F50
F12
F130
F2
F105
F115
F50
F12
F130
F2
F22
0
_
0
100
0
0
16
10
0
1
0
0
1
20
0
1
_
0 to 3
0 to 300
1
1
–
s
F138
F1
0
15
0 to 2000
0 to 150
0 to 359
0 to 2000
0 to 2000
0 to 1000
–50 to 250
–50 to 250
–50 to 250
–50 to 250
50 to 900
0 to 100
0 to 100
0 to 100
0 to 100
–50 to 250
–50 to 250
–50 to 250
–50 to 250
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
× CT
× Rated
°
× CT
× CT
Volts
°C
°C
°C
°C
Hz
%
%
%
%
°F
°F
°F
°F
F3
F3
F1
F3
F3
F2
F4
F4
F4
F4
F2
F1
F1
F1
F1
F4
F4
F4
F4
0
100
0
0
0
0
40
40
40
40
600
0
0
0
0
40
40
40
40
0 to 2000
0 to 150
0 to 359
1
1
1
× CT
× Rated
°
F3
F3
F1
0
100
0
489 Generator Management Relay
6
6-31
6.3 MODBUS MEMORY MAP
6 COMMUNICATIONS
Table 6–1: 489 MEMORY MAP (SHEET 23 OF 24)
6
ADDR NAME
2D83 FAULT Iphase NEUTRAL
2D84 FAULT CURRENT GROUND
2D85 FAULT VOLTAGE NEUTRAL
2D86 FAULT STATOR RTD TEMP
2D87 FAULT BEARING RTD TEMP
2D88 FAULT OTHER RTD TEMP
2D89 FAULT AMBIENT RTD TEMP
2D8A FAULT SYSTEM FREQUENCY
2D8B FAULT ANALOG INPUT 1
2D8C FAULT ANALOG INPUT 2
2D8D FAULT ANALOG INPUT 3
2D8E FAULT ANALOG INPUT 4
2DBC FAULT STATOR RTD TEMP
2DBD FAULT BEARING RTD TEMP
2DBE FAULT OTHER RTD TEMP
2DBF FAULT AMBIENT RTD TEMP
489 TESTING / TEST OUTPUT RELAYS
2DE0 FORCE OPERATION OF RELAYS
489 TESTING / TEST ANALOG OUTPUT
2DF0 FORCE ANALOG OUTPUTS FUNCTION
2DF1 ANALOG OUTPUT 1 FORCED VALUE
2DF2 ANALOG OUTPUT 2 FORCED VALUE
2DF3 ANALOG OUTPUT 3 FORCED VALUE
2DF4 ANALOG OUTPUT 4 FORCED VALUE
EVENT RECORDER / GENERAL
3000 EVENT RECORDER LAST RESET DATE (2 WORDS)
3002 TOTAL NUMBER OF EVENTS SINCE LAST CLEAR
3003 EVENT RECORD SELECTOR
EVENT RECORDER / SELECTED EVENT
3004 CAUSE OF EVENT
3005 TIME OF EVENT (2 WORDS)
3007 DATE OF EVENT (2 WORDS)
3009 TACHOMETER
300A PHASE A CURRENT
300C PHASE B CURRENT
300E PHASE C CURRENT
3010 PHASE A DIFFERENTIAL CURRENT
3012 PHASE B DIFFERENTIAL CURRENT
3014 PHASE C DIFFERENTIAL CURRENT
3016 NEG. SEQ. CURRENT
3017 GROUND CURRENT
3019 A-B VOLTAGE
301A B-C VOLTAGE
301B C-A VOLTAGE
301C FREQUENCY
301D ACTIVE GROUP
301F REAL POWER (MW)
3021 REACTIVE POWER Mar
3023 APPARENT POWER MVA
3025 HOTTEST STATOR RTD #
3026 HOTTEST STATOR RTD TEMPERATURE
3027 HOTTEST BEARING RTD #
3028 HOTTEST BEARING RTD TEMPERATURE
3029 HOTTEST OTHER RTD #
302A HOTTEST OTHER RTD TEMPERATURE
302B HOTTEST AMBIENT RTD #
302C HOTTEST AMBIENT RTD TEMPERATURE
302D ANALOG IN 1
302F ANALOG IN 2
3031 ANALOG IN 3
3033 ANALOG IN 4
3035 PHASE A NEUTRAL CURRENT
3037 PHASE B NEUTRAL CURRENT
3039 PHASE C NEUTRAL CURRENT
30E0 HOTTEST STATOR RTD TEMPERATURE
30E1 HOTTEST BEARING RTD TEMPERATURE
1, 2, 3
See Table footnotes on page 6–33
6-32
RANGE
0 to 2000
0 to 2000
0 to 1000
–50 to 250
–50 to 250
–50 to 250
–50 to 250
50 to 900
0 to 100
0 to 100
0 to 100
0 to 100
–50 to 250
–50 to 250
–50 to 250
–50 to 250
STEP
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
UNITS
× CT
× CT
Volts
°C
°C
°C
°C
Hz
%
%
%
%
°F
°F
°F
°F
FORMAT
F3
F3
F2
F4
F4
F4
F4
F2
F1
F1
F1
F1
F4
F4
F4
F4
DEFAULT
0
0
0
40
40
40
40
600
0
0
0
0
40
40
40
40
0 to 8
1
–
F139
0
0 to 1
0 to 100
0 to 100
0 to 100
0 to 100
1
1
1
1
1
–
%
%
%
%
F126
F1
F1
F1
F1
0
0
0
0
0
N/A
0 to 65535
0 to 65535
N/A
1
1
N/A
N/A
–
F18
F1
F1
N/A
N/A
0
0 to 139
N/A
N/A
0 to 7200
0 to 999999
0 to 999999
0 to 999999
0 to 999999
0 to 999999
0 to 999999
0 to 2000
0 to 20000000
0 to 50000
0 to 50000
0 to 50000
0 to 12000
0 to 1
–2000000 to 2000000
–2000000 to 2000000
0 to 2000000
1 to 12
–50 to 250
1 to 12
–50 to 250
1 to 12
–50 to 250
1 to 12
–50 to 250
–50000 to 50000
–50000 to 50000
–50000 to 50000
–50000 to 50000
0 to 999999
0 to 999999
0 to 999999
–50 to 250
–50 to 250
1
N/A
N/A
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
–
N/A
N/A
RPM
Amps
Amps
Amps
Amps
Amps
Amps
%FLA
A
Volts
Volts
Volts
Hz
–
MW
Mar
MVA
–
°C
–
°C
–
°C
–
°C
Units
Units
Units
Units
Amps
Amps
Amps
°F
°F
F134
F19
F18
F1
F12
F12
F12
F12
F12
F12
F1
F14
F1
F1
F1
F3
F1
F13
F13
F13
F1
F4
F1
F4
F1
F4
F1
F4
F12
F12
F12
F12
F12
F12
F12
F4
F4
0
N/A
N/A
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
0
1
0
1
0
1
0
0
0
0
0
0
0
0
0
0
489 Generator Management Relay
GE Multilin
6 COMMUNICATIONS
6.3 MODBUS MEMORY MAP
Table 6–1: 489 MEMORY MAP (SHEET 24 OF 24)
ADDR NAME
30E2 HOTTEST OTHER RTD TEMPERATURE
30E3 HOTTEST AMBIENT RTD TEMPERATURE
30E5 NEUTRAL VOLT (FUND)
30E7 NEUTRAL VOLT (3rd)
30E9 Vab/Iab
30EA Vab/Iab ANGLE
WAVEFORM MEMORY SETUP
30F0 WAVEFORM MEMORY TRIGGER DATE
30F2 WAVEFORM MEMORY TRIGGER TIME
30F4 FREQUENCY DURING TRACE ACQUISITION
30F5 WAVEFORM MEMORY CHANNEL SELECTOR
(HOLDING REGISTER)
30F6 WAVEFORM TRIGGER SELECTOR
30F7 WAVEFORM TRIGGER CAUSE (READ-ONLY)
30F8 NUMBER OF SAMPLES PER WAVEFORM CAPTURE
30F9 NUMBER OF WAVEFORM CAPTURES TAKEN
WAVEFORM MEMORY SAMPLES
3100 FIRST WAVEFORM MEMORY SAMPLE
3400 LAST WAVEFORM MEMORY SAMPLE
1, 2, 3
See Table footnotes on page 6–33
1.
2.
3.
RANGE
–50 to 250
–50 to 250
0 to 250000
0 to 250000
0 to 65535
0 to 359
STEP
1
1
1
1
1
1
UNITS
°F
°F
Volts
Volts
ohms s
°
FORMAT
F4
F4
F10
F10
F1
F1
DEFAULT
0
0
0
0
0
0
N/A
N/A
0 to 12000
0 to 9
N/A
N/A
1
1
N/A
N/A
Hz
N/A
F18
F19
F3
F214
N/A
N/A
0
0
1 to 65535
0 to 139
1 to 768
0 to 65535
1
1
1
1
N/A
N/A
N/A
N/A
F1
F134
F1
F1
0
0
168
0
–32767 to 32767
–32767 to 32767
1
1
N/A
N/A
F4
F4
0
0
Value of 65535 indicates ‘Never’
A value of 0xFFFF indicates “no measurable value”.
Maximum value turns feature ‘Off’
6
GE Multilin
489 Generator Management Relay
6-33
6.3 MODBUS MEMORY MAP
6 COMMUNICATIONS
6.3.8 MEMORY MAP DATA FORMATS
Table 6–2: DATA FORMATS (SHEET 1 OF 5)
6
FORMAT
CODE
F1
TYPE
DEFINITION
16 bits
F2
16 bits
F3
16 bits
F4
16 bits
F5
16 bits
F6
16 bits
F10
32 bits
F12
32 bits
F13
32 bits
F14
32 bits
F15
16 bits
F16
16 bits
F18
32 bits
F19
32 bits
F22
16 bits
F24
32 bits
F50
16 bits
F100
Unsigned
16 bit integer
Unsigned
16 bit integer
Unsigned
16 bit integer
Unsigned
16 bit integer
Unsigned
16 bit integer
Unsigned
16 bit integer
Unsigned
16 bit integer
Unsigned Value
Example: 1234 stored as 1234
Unsigned Value, 1 Decimal Place
Example: 123.4 stored as 1234
Unsigned Value, 2 Decimal Places
Example: 12.34 stored as 1234
2’s Complement Signed Value
Example, –1234 stored as –1234 (i.e., 64302)
2’s Complement Signed Value, 1 Decimal Place
Example, –1.234 stored as –1234 (i.e., 64302)
2’s Complement Signed Value, 2 Decimal Places
Example, –12.34 stored as –1234 (i.e., 64302)
2’s Complement Signed Long Value, 1 Decimal Place
1st 16 bits: High order word of long value
2nd 16 bits: Low order word of long value
Example: –12345.6 stored as –123456 (i.e., 1st word FFFE hex, 2nd word 1DC0 hex)
2’s Complement Signed Long Value
1st 16 bits: High order word of long value
2nd 16 bits: Low order word of long value
Example: –123456 stored as 1st word FFFE hex, 2nd word 1DC0 hex
2’s Compliment Signed Long Value, 3 Decimal Places
1st 16 bits: High order word of long value
2nd 16 bits: Low order word of long value
Example: –123.456 stored as -123456 (i.e., 1st word FFFE hex, 2nd word 1DC0 hex)
2’s Complement Signed Long Value, 2 Decimal Places
1st 16 bits: High order word of long value
2nd 16 bits: Low order word of long value
Example: –1234.56 stored as –123456 (i.e., 1st word FFFE hex, 2nd word 1DC0 hex)
Hardware Revision
1 = revision A, 2 = revision B, 3 = revision C,..., 26 = revision Z
Software Revision
1111 1111 XXXX XXXX: Major revision number – 0 to 9 in steps of 1
XXXX XXXX 1111 1111: Minor revision number (two BCD digits) 00 to 99 in steps of 1
Example: Revision 2.30 stored as 0230 hex
Date (MM/DD/YYYY)
1st byte: Month (1 to 12)
2nd byte: Day (1 to 31)
3rd and 4th byte: Year (1996 to 2094)
Example: Feb. 20, 1996 stored as 34867148 (i.e., first word 0214, 2nd word 07CC)
Time (HH:MM:SS:hh)
1st byte: Hours (0 to 23)
2nd byte: Minutes (0 to 59)
3rd byte: Seconds (0 to 59)
4th byte: Hundredths of seconds (0 to 99)
Example: 2:05pm stored as 235208704 (i.e., 1st word 0E05, 2nd word 0000)
Character String (Note: Range indicates number of characters)
1st byte (MSB) of each word: First of a pair of characters
2nd byte (LSB) of each word: Second of a pair of characters
Example: String “AB” stored as 4142 hex
Time Format for Broadcast
1st byte: Hours (0 to 23)
2nd byte: Minutes (0 to 59)
3rd and 4th bytes: Milliseconds (0 to 59999). Note: Clock resolution limited to 1/100 sec.
Example: 1:15:48:572 stored as 17808828 (i.e., 1st word 010F, 2nd word BDBC)
Relay List (Bitmap)
Bit 0 = Relay 1, Bit 1 =Relay 2, Bit 2 = Relay 3, Bit 3 = Relay 4, Bit 4 = Relay 5, Bit 5 = Relay 6
Temperature display units
0 = Celsius, 1 = Fahrenheit
RS485 baud rate
0 = 300, 1 = 1200, 2 = 2400, 3 = 4800, 4 = 9600, 5 = 19200
RS485 parity
0 = None, 1 = Odd, 2 = Even
No / Yes selection
0 = No, 1 = Yes
Ground CT type
0 = None, 1 = 1 A Secondary, 2 = 50:0.025 Ground CT, 3 = 5 A Secondary
Off / On selection
0 = Off, 1 = On
VT connection type
0 = None, 1 = Open Delta, 2 = Wye
F101
F102
F103
F104
F105
F106
6-34
489 Generator Management Relay
GE Multilin
6 COMMUNICATIONS
6.3 MODBUS MEMORY MAP
Table 6–2: DATA FORMATS (SHEET 2 OF 5)
FORMAT
CODE
F107
F109
F115
F117
F118
F120
F121
F122
F123
F124
F126
F127
F128
F129
F130
TYPE
DEFINITION
Unsigned
16 bit integer
Unsigned
16 bit integer
Unsigned
16 bit integer
Unsigned
16 bit integer
Unsigned
16 bit integer
Unsigned
16 bit integer
Unsigned
16 bit integer
Unsigned
16 bit integer
Unsigned
16 bit integer
Unsigned
16 bit integer
Unsigned
16 bit integer
Unsigned
16 bit integer
Nominal frequency selection
0 = -----, 1 = 60 Hz, 2 = 50 Hz, 3 = 25 Hz
Breaker status switch type
0 = Auxiliary a, 1 = Auxiliary b
Alarm / trip type selection
0 = Off, 1 = Latched, 2 = Unlatched
Reset mode
0 = All Resets, 1 = Remote Reset Only
Setpoint Group
0 = Group 1, 1 = Group 2
RTD type
0 = 100 Ohm Platinum, 1 = 120 Ohm Nickel, 2 = 100 Ohm Nickel, 3 = 10 Ohm Copper
RTD application
0 = None, 1 = Stator, 2 = Bearing, 3 = Ambient, 4 = Other
RTD voting selection
1 = RTD #1, 2 = RTD #2, 3= RTD #3,..., 12 = RTD #12
Alarm / trip status
0 = Not Enabled, 1 = Inactive, 2 = Timing Out, 3 = Active Trip, 4 = Latched Trip
Phase rotation selection
0 = ----, 1 = ABC, 2 = ACB
Disabled / Enabled selection
0 = Disabled, 1 = Enabled
Analog output parameter selection
Unsigned
16 bit integer
Unsigned
16 bit integer
Unsigned
16 bit integer
GE Multilin
VALUE
PARAMETER
VALUE
PARAMETER
0
None
22
AB Voltage
1
IA Output Current
23
BC Voltage
2
IB Output Current
24
CA Voltage
3
IC Output Current
25
Average Voltage
4
Avg. Output Current
26
Volts / Hertz
5
Neg. Seq. Current
27
Frequency
6
Averaged Gen. Load
28
Neutral Voltage (3rd)
7
Hottest Stator RTD
29
Power Factor
8
Hottest Bearing RTD
30
Reactive Power (Mvar)
9
Ambient RTD
31
Real Power (MW)
10
RTD #1
32
Apparent Power (MVA)
11
RTD #2
33
Analog Input 1
12
RTD #3
34
Analog Input 2
13
RTD #4
35
Analog Input 3
14
RTD #5
36
Analog Input 4
15
RTD #6
37
Tachometer
16
RTD #7
38
Therm. Capacity Used
17
RTD #8
39
Current Demand
18
RTD #9
40
Mar Demand
19
RTD #10
41
MW Demand
20
RTD #11
42
MVD Demand
6
21
RTD #12
Overcurrent curve style selection
VALUE
PARAMETER
VALUE
0
ANSI Extremely Inverse
7
IEC Short Inverse
1
ANSI Very Inverse
8
IAC Extremely Inverse
2
ANSI Normally Inverse
9
IAC Very Inverse
3
ANSI Moderately Inverse
10
IAC Inverse
4
IEC Curve A (BS142)
11
IAC Short Inverse
5
IEC Curve B (BS142)
12
Flexcurve™
6
IEC Curve C (BS142)
13
Analog input selection
0 = Disabled, 1 = 4-20 mA, 2 = 0-20 mA, 3 = 0-1 mA
Pickup type
0 = Over, 1 = Under
PARAMETER
Definite Time
489 Generator Management Relay
6-35
6.3 MODBUS MEMORY MAP
6 COMMUNICATIONS
Table 6–2: DATA FORMATS (SHEET 3 OF 5)
FORMAT
CODE
F131
F132
F133
F134
TYPE
DEFINITION
Unsigned
16 bit integer
Unsigned
16 bit integer
Unsigned
16 bit integer
Unsigned
16 bit integer
Input switch status
0 = Closed, 1 = Open
Trip coil supervision status
0 = No Coil, 1 = Coil
Generator status
0 = Offline, 1 = Offline, 2 = Online, 3 = Overload, 4 = Tripped
Cause of event / Cause of trip
6
F136
16 bits
F138
Unsigned
16 bit integer
6-36
VALUE PARAMETER
VALUE PARAMETER
VALUE
0
No Event
47
Field-Bkr Discrep.
94
1
General Sw. A Trip
48
Offline O/C Trip
95
2
General Sw. B Trip
49
Phase O/C Trip
96
3
General Sw. C Trip
50
Neg. Seq. O/C Trip
97
4
General Sw. D Trip
51
General Sw. A Alarm
98
5
General Sw. E Trip
52
General Sw. B Alarm
99
6
General Sw. F Trip
53
General Sw. C Alarm
100
7
General Sw. G Trip
54
General Sw. D Alarm
101
8
Sequential Trip
55
General Sw. E Alarm
102
9
Tachometer Trip
56
General Sw. F Alarm
103
10
UNKNOWN TRIP
57
General Sw. G Alarm
104
11
UNKNOWN TRIP
58
105
12
Overload Trip
59
Tachometer Alarm
106
13
UNKNOWN TRIP
60
Thermal Model Alarm
107
14
Neutral O/V Trip
61
Overload Alarm
108
15
Neut. U/V (3rd) Trip
62
Underfrequency Alarm
109
16
63
110
17
64
Ground Fault Alarm
111
18
65
RTD 1 Alarm
112
19
66
RTD 2 Alarm
113
20
Differential Trip
67
RTD 3 Alarm
114
21
Acceleration Trip
68
RTD 4 Alarm
115
22
RTD 1 Trip
69
RTD 5 Alarm
116
23
RTD 2 Trip
70
RTD 6 Alarm
117
24
RTD 3 Trip
71
RTD 7 Alarm
118
25
RTD 4 Trip
72
RTD 8 Alarm
119
26
RTD 5 Trip
73
RTD 9 Alarm
120
27
RTD 6 Trip
74
RTD 10 Alarm
121
28
RTD 7 Trip
75
RTD 11 Alarm
122
29
RTD 8 Trip
76
RTD 12 Alarm
123
30
RTD 9 Trip
77
Open RTD Alarm
124
31
RTD 10 Trip
78
Short/Low RTD Alarm
125
32
RTD 11 Trip
79
Undervoltage Alarm
126
33
RTD 12 Trip
80
Overvoltage Alarm
127
34
Undervoltage Trip
81
Overfrequency Alarm
128
35
Overvoltage Trip
82
Power Factor Alarm
129
36
Phase Reversal Trip
83
Reactive Power Alarm
130
37
Overfrequency Trip
84
Low Fwd Power Alarm
131
38
Power Factor Trip
85
Trip Counter Alarm
132
39
Reactive Power Trip
86
Breaker Fail Alarm
133
40
Underfrequency Trip
87
Current Demand Alarm
134
41
Analog I/P 1 Trip
88
kW Demand Alarm
135
42
Analog I/P 2 Trip
89
kvar Demand Alarm
136
43
Analog I/P 3 Trip
90
kVA Demand Alarm
137
44
Analog I/P 4 Trip
91
Broken Rotor Bar
138
45
Single Phasing Trip
92
Analog I/P 1 Alarm
139
46
Reverse Power Trip
93
Analog I/P 2 Alarm
Order Code
Bit 0: 0 = Code P5 (5A CT secondaries), 1 = Code P1 (1A CT secondaries)
Bit 1: 0 = Code HI (High voltage power supply), 1 = Code LO (Low voltage power supply)
Bit 2: 0 = Code A20 (4-20 mA analog outputs), 1 = Code A1 (0-1 mA analog outputs)
Simulation mode
0 = Off, 1 = Simulate Pre-Fault, 2 = Simulate Fault, 3 = Pre-Fault to Fault
489 Generator Management Relay
PARAMETER
Analog I/P 3 Alarm
Analog I/P 4 Alarm
Reverse Power Alarm
Incomplete Seq.Alarm
Negative Seq. Alarm
Ground O/C Alarm
Service Alarm
Control Power Lost
Cont. Power Applied
Thermal Reset Close
Emergency Rst. Open
Start While Blocked
Relay Not Inserted
Trip Coil Super.
Breaker Failure
VT Fuse Failure
Simulation Started
Simulation Stopped
Ground O/C Trip
Volts/Hertz Trip
Volts/Hertz Alarm
Low Fwd Power Trip
Inadvertent Energ.
Serial Start Command
Serial Stop Command
Input A Control
Input B Control
Input C Control
Input D Control
Input E Control
Input F Control
Input G Control
Neutral O/V Alarm
Neut. U/V 3rd Alarm
Setpoint 1 Active
Setpoint 2 Active
Loss of Excitation 1
Loss of Excitation 2
Gnd. Directional Trip
Gnd. Directional Alarm
HiSet Phase O/C Trip
Distance Zone 1 Trip
Distance Zone 2 Trip
Dig I/P Wavefrm Trig
Serial Waveform Trig
GE Multilin
6 COMMUNICATIONS
6.3 MODBUS MEMORY MAP
Table 6–2: DATA FORMATS (SHEET 4 OF 5)
FORMAT
CODE
F139
TYPE
DEFINITION
Unsigned
16 bit integer
Force operation of relays
VALUE
F140
16 bits
16 bits
R1 Trip
6
R6 Service
2
R2 Auxiliary
7
All Relays
3
F200
F201
F202
F206
F207
F208
F209
F210
Unsigned
16 bit integer
Unsigned
16 bit integer
Unsigned
16 bit integer
Unsigned
16 bit integer
Unsigned
16 bit integer
Unsigned
16 bit integer
Unsigned
16 bit integer
R3 Auxiliary
8
No Relays
PARAMETER
BIT NO.
PARAMETER
Bit 0
Relay in Service
Bit 8
Breaker Open LED
Bit 1
Active Trip Condition
Bit 9
Breaker Closed LED
Bit 2
Active Alarm Condition
Bit 10
Hot Stator LED
Bit 3
Reserved
Bit 11
Neg. Sequence LED
Bit 4
Reserved
Bit 12
Ground LED
Bit 5
Reserved
Bit 13
Loss of Field LED
Bit 6
Reserved
Bit 14
VT Failure LED
Bit 7
Simulation Mode Enabled
Output Relay Status
Bit 15
Breaker Failure LED
PARAMETER
R1 Trip
BIT NO.
Bit 8
PARAMETER
Reserved
Bit 1
R2 Auxiliary
Bit 9
Reserved
Bit 2
R3 Auxiliary
Bit 10
Reserved
Bit 3
R4 Auxiliary
Bit 11
Reserved
Bit 4
R5 Alarm
Bit 12
Reserved
Bit 5
R6 Service
Bit 13
Reserved
Bit 6
Reserved
Bit 14
Reserved
Bit 15
Reserved
Bit 7
Reserved
Thermal Model curve style selection
0 = Standard, 1 = Custom, 2 = Voltage Dependent
Comm. monitor buffer status
VALUE
PARAMETER
VALUE
0
Buffer Cleared
4
Illegal Count
1
Received OK
5
Illegal Reg. Addr.
2
Wrong Slave Addr.
6
CRC Error
7
Illegal Data
3
Illegal Function
Curve Reset Type
0 = Instantaneous, 1 = Linear
Inadvertent energization arming type
0 = U/V and Offline, 1 = U/V or Offline
Sequential trip type
0 = Low Forward Power, 1 = Reverse Power
Switch status
0 = Open, 1 = Shorted
Undervoltage trip element type
0 = Curve, 1 = Definite Time
Breaker operation type
0 = Breaker Auxiliary a, 1 = Breaker Auxiliary b
Assignable input selection
VALUE
GE Multilin
R5 Alarm
4
R4 Auxiliary
General Status
Bit 0
Unsigned
16 bit integer
Unsigned
16 bit integer
5
PARAMETER
1
BIT NO.
F142
VALUE
Disabled
BIT NO.
F141
PARAMETER
0
PARAMETER
VALUE
6
PARAMETER
PARAMETER
0
None
4
Input 4
1
Input 1
5
Input 5
2
Input 2
6
Input 6
3
Input 3
7
Input 7
489 Generator Management Relay
6-37
6.3 MODBUS MEMORY MAP
6 COMMUNICATIONS
Table 6–2: DATA FORMATS (SHEET 5 OF 5)
FORMAT
CODE
F211
F212
TYPE
DEFINITION
Unsigned
16 bit integer
Unsigned
16 bit integer
Volts/Hertz element type
0 = Curve #1, 1 = Curve #2, 2 = Curve #2, 3 = Definite Time
RTD number
VALUE
F213
F214
Unsigned
16 bit integer
Unsigned 16 bit
integer
PARAMETER
VALUE
PARAMETER
0
All
7
RTD #7
1
RTD #1
8
RTD #8
2
RTD #2
9
RTD #9
3
RTD #3
10
RTD #10
4
RTD #4
11
RTD #11
5
RTD #5
12
RTD #12
6
RTD #6
Communications monitor port selection
0 = Computer RS485, 1 = Auxiliary RS485, 2 = Front Panel RS232
Waveform Memory Channel Selector
VALUE PARAMETER
VALUE PARAMETER
0
Phase A line current
512 counts = 1 × CT
5
Neutral-end phase C line current
512 counts = 1 × CT
1
Phase B line current
512 counts = 1 × CT
6
Ground current
512 counts = 1 × CT
2
Phase C line current
512 counts = 1 × CT
7
Phase A to neutral voltage
3500 counts = 120 secondary volts
3
Neutral-end phase A line current
512 counts = 1 × CT
8
Phase B to neutral voltage
3500 counts = 120 secondary volts
4
F215
F216
6
F217
F218
F219
F220
6-38
Unsigned
16 bit integer
Unsigned
16 bit integer
Unsigned
16 bit integer
Unsigned
16 bit integer
Unsigned
16 bit integer
Unsigned
16 bit integer
Neutral-end phase B line current
9
Phase C to neutral voltage
512 counts equals 1 × CT
3500 counts = 120 secondary volts
Current Source
0 = Neutral-end CTs; 1 = Output-end CTs
DNP Port Selection
0 = None, 1 = Computer RS485, 2 = Auxiliary RS485, 3 = Front Panel RS485
Ground Directional MTA
0 = 0°, 1 = 90°, 2 = 180°, 3 = 270°
Breaker State
0 = 52 Closed, 1 = 52 Open/Closed
Step Up Transformer Type
0 = None, 1 = Delta/Wye
IRIG-B Type
0 = None, 1 = DC Shift, 2 = Amplitude Modulated
489 Generator Management Relay
GE Multilin
6 COMMUNICATIONS
6.4 DNP PROTOCOL
6.4DNP PROTOCOL
6.4.1 DEVICE PROFILE DOCUMENT
DNP 3.0
DEVICE PROFILE DOCUMENT
Vendor Name: General Electric Multilin Inc.
Device Name: 489 Generator Management Relay
Highest DNP Level Supported:
For Requests: Level 2
For Responses: Level 2
Device Function:
 Slave
Master 
Notable objects, functions, and/or qualifiers supported in addition to the Highest DNP Levels Supported (the complete
list is described in the attached table):
Binary Input (Object 1, Variations 1 and 2)
Binary Output (Object 10, Variation 2)
Binary Counter (Object 20, Variations 5 and 6)
Frozen Counter (Object 21, Variations 9 and 10)
Analog Input (Object 30, Variations 1, 2, 3, and 4)
Analog Input Change (Object 32, Variations 1, 2, 3, and 4)
Warm Restart (Function code 14)
Maximum Data Link Frame Size (octets):
Transmitted: 292
Received: 292
Maximum Application Fragment Size (octets):
Transmitted: 2048
Received: 2048
Maximum Data Link Re-tries:

  None
 Fixed
 Configurable
Maximum Application Layer Re-tries:


None
 Configurable
Requires Data Link Layer Confirmation:

  Never
 Always
 Sometimes
 Configurable
Requires Application Layer Confirmation:
 Never
 Always


When reporting Event Data
 When sending multi-fragment responses
 Sometimes
 Configurable
Timeouts while waiting for:
Data Link Confirm
Complete Appl. Fragment
Application Confirm
Complete Appl. Response
Others:

 None

 None

 None

 None
(None)




Fixed
Fixed
Fixed
Fixed




Variable
Variable
Variable
Variable




6
Configurable
Configurable
Configurable
Configurable
Executes Control Operations:

 Never
WRITE Binary Outputs
 Always
 Sometimes
 Configurable

 Never
SELECT/OPERATE
 Always
 Sometimes
 Configurable

 Always
DIRECT OPERATE
 Never
 Sometimes
 Configurable

 Always
DIRECT OPERATE: NO ACK
 Never
 Sometimes
 Configurable

 Never
Count > 1
 Always
 Sometimes
 Configurable

 Always
Pulse On
 Never
 Sometimes
 Configurable

 Never
Pulse Off
 Always
 Sometimes
 Configurable

 Never
Latch On
 Always
 Sometimes
 Configurable

 Never
Latch Off
 Always
 Sometimes
 Configurable
(For an explanation of the above, refer to the discussion accompanying the point list for the Binary Output/Control
Relay Output Block objects)

 Never
Queue
 Always
 Sometimes
 Configurable

 Never
Clear Queue
 Always
 Sometimes
 Configurable
GE Multilin
489 Generator Management Relay
6-39
6.4 DNP PROTOCOL
6 COMMUNICATIONS
DNP 3.0
DEVICE PROFILE DOCUMENT (CONTINUED)
Reports Binary Input Change Events when no specific
variations requested:

Never


Only time-tagged

Only non-time-tagged

Configurable to send both, one or the other
Reports time-tagged Binary Input Change Events when no
specific variation requested:

Never


Binary Input Change With Time

Binary Input Change With Relative Time

Configurable
Sends Unsolicited Responses:


Never

Configurable

Only certain objects

Sometimes

ENABLE/DISABLE UNSOLICITED
Function codes supported
Sends Static Data in Unsolicited Responses:


Never

When Device Restarts

When Status Flags Change
Default Counter Object/Variation:

No Counters Reported

Configurable


Default Object
Default Variation

Point-by-point list attached
Counters Roll Over at:

No Counters Reported

Configurable

16 Bits

32 Bits

Other Value


Point-by-point list attached
Sends Multi-Fragment Responses:

Yes

 No
6
6-40
489 Generator Management Relay
GE Multilin
6 COMMUNICATIONS
6.4 DNP PROTOCOL
6.4.2 IMPLEMENTATION TABLE
The table below gives a list of all objects recognized and returned by the relay. Additional information is provided on the following pages including a list of the default variations returned for each object and lists of defined point numbers for each
object.
Table 6–3: DNP IMPLEMENTATION TABLE
OBJECT
DESCRIPTION
REQUEST
FUNC.
CODES
RESPONSE
OBJ
VAR
QUAL.
CODES
(HEX)
FUNC.
CODES
QUAL.
CODES
(HEX)
1
0
Binary Input - All Variations
1
06
1
1
Binary Input
1
00, 01, 06
1
2
Binary Input With Status
129
00, 01
1
00, 01, 06
129
2
0
00, 01
Binary Input Change - All Variations
1
06, 07, 08
2
2
1
Binary Input Change Without Time
1
06, 07, 08
129
17, 28
2
Binary Input Change With Time
1
06, 07, 08
129
17, 28
10
0
Binary Output - All Variations
1
06
10
2
Binary Output Status
1
00, 01, 06
129
00, 01
12
1
Control Relay Output Block
5, 6
17, 28
129
17, 28
20
0
Binary Counter - All Variations
1,7,8,9,10
06
129
00, 01
20
5
32-Bit Binary Counter without Flag
1,7,8,9,10
06
129
00, 01
20
6
16-Bit Binary Counter without Flag
1,7,8,9,10
06
129
00, 01
00, 01
21
0
Frozen Counter - All Variations
1
06
129
21
9
32-Bit Frozen Counter without Flag
1
06
129
00, 01
21
10
16-Bit Frozen Counter without Flag
1
06
129
00, 01
30
0
Analog Input - All Variations
1
06
30
1
32-Bit Analog Input With Flag
1
00, 01, 06
129
00, 01
30
2
16-Bit Analog Input With Flag
1
00, 01, 06
129
00, 01
30
3
32-Bit Analog Input Without Flag
1
00, 01, 06
129
00, 01
30
4
16-Bit Analog Input Without Flag
1
00, 01, 06
129
00, 01
32
0
Analog Input Change - All Variations
1
06, 07, 08
32
1
32-Bit Analog Input Change Without Time
1
06, 07, 08
129
17, 28
32
2
16-Bit Analog Input Change Without Time
1
06, 07, 08
129
17, 28
32
3
32-Bit Analog Input Change With Time
1
06, 07, 08
129
17, 28
32
4
16-Bit Analog Input Change With Time
50
1
Time and Date
1
06, 07, 08
129
17, 28
1, 2
07 (Note 1)
129
60
1
07
Class 0 Data (Note 2)
1
06
129
60
2
Class 1 Data (Note 3)
1
06, 07, 08
129
60
3
Class 2 Data (Note 3)
1
06, 07, 08
129
60
4
Class 3 Data (Note 3)
1
06, 07, 08
129
80
1
Internal Indications
2
00 (Note 4)
129
No object (cold restart command)
13
No object (warm restart command)
14
No object (delay measurement command) (Note 5)
23
6
For Notes, see the IMPLEMENTATION TABLE NOTES on the following page.
GE Multilin
489 Generator Management Relay
6-41
6.4 DNP PROTOCOL
6 COMMUNICATIONS
IMPLEMENTATION TABLE NOTES:
1.
For this object, the quantity specified in the request must be exactly 1 as there is only one instance of this object
defined in the relay.
2.
All static data known to the relay is returned in response to a request for Class 0. This includes all objects of type 1
(Binary Input), type 10 (Binary Output), type 20 (Binary Counter), type 21 (Frozen Counter) and type 30 (Analog Input).
3.
The point tables for Binary Input and Analog Input objects contain a field that defines to which event class the corresponding static data point has been assigned.
4.
For this object, the qualifier code must specify an index of 7 only.
5.
Delay Measurement (function code 23) is supported since the relay allows for writing the time via object 50 and it also
periodically sets the “Time Synchronization Required” Internal Indication (IIN). The IIN is set at power-up and will be
set again 24 hours after it was last cleared. The IIN is cleared when time is written as object 50 data or if IRIG-B is
enabled and relay time is updated as a result of a successful decoding of this signal.
6.4.3 DEFAULT VARIATIONS
The following table specifies the default variation for all objects returned by the relay. These are the variations that will be
returned for the object in a response when no specific variation is specified in a request.
Table 6–4: DEFAULT VARIATIONS
6
OBJECT
DESCRIPTION
1
Binary Input - Single Bit
1
2
Binary Input Change With Time
2
10
Binary Output Status
2
20
16-Bit Binary Counter without Flag
6
21
16-Bit Frozen Counter without Flag
10
30
32-Bit Analog Input Without Flag
3
32
32-Bit Analog Input Change Without Time
1
6-42
DEFAULT
VARIATION
489 Generator Management Relay
GE Multilin
6 COMMUNICATIONS
6.5 DNP POINT LISTS
6.5DNP POINT LISTS
6.5.1 BINARY INPUT / BINARY INPUT CHANGE (OBJECTS 01/02)
The point list for Binary Inputs (Object 01) and Binary Input Change (Object 02) is shown below:
Table 6–5: BINARY INPUT POINTS (SHEET 1 OF 4)
INDEX
Table 6–5: BINARY INPUT POINTS (SHEET 2 OF 4)
DESCRIPTION
EVENT
CLASS
INDEX
DESCRIPTION
EVENT
CLASS
0
Relay In Service
Class 1
1
Trip Condition Active
Class 1
47
Sequential Trip Active or Latched
Class 1
48
Field-Breaker Discrepancy Trip Active
or Latched
2
Alarm Condition Active
Class 1
Class 1
3
Simulation Mode Enabled
Class 1
4
Breaker Is Open
Class 1
5
Breaker Is Closed
Class 1
49
Tachometer Trip Active or Latched
Class 1
50
Offline O/C Trip Active or Latched
Class 1
51
Inadvertent Energization Trip Active or
Latched
Class 1
Class 1
6
Hot Stator Fault Active
Class 1
52
Phase O/C Trip Active or Latched
7
Negative Sequence Fault Active
Class 1
53
Neg. Seq. O/C Trip Active or Latched
Class 1
8
Ground Fault Active
Class 1
54
Ground O/C Trip Active or Latched
Class 1
55
Phase Differential Trip Active or
Latched
Class 1
9
Loss Of Field Fault Active
Class 1
10
VT Failure Detected
Class 1
11
Breaker Failure Detected
Class 1
56
Undervoltage Trip Active or Latched
Class 1
Overvoltage Trip Active or Latched
Class 1
Class 1
12
Relay 1 Trip Operated
Class 1
57
13
Relay 2 Auxiliary Operated
Class 1
58
Volts/Hertz Trip Active or Latched
14
Relay 3 Auxiliary Operated
Class 1
59
Phase Reversal Trip Active or Latched
Class 1
15
Relay 4 Auxiliary Operated
Class 1
60
Underfrequency Trip Active or Latched
Class 1
16
Relay 5 Alarm Operated
Class 1
61
Overfrequency Trip Active or Latched
Class 1
62
Neutral O/V (Fund) Trip Active /
Latched
Class 1
63
Neutral U/V (3rd Harmonic) Trip Active
or Latched
Class 1
17
Relay 6 Service Operated
Class 1
18
Setpoint Access Input Closed
Class 1
19
Breaker Status Input Closed
Class 1
20
Assignable Input 1 Closed
Class 1
64
Reactive Power Trip Active or Latched
Class 1
21
Assignable Input 2 Closed
Class 1
65
Reverse Power Trip Active or Latched
Class 1
22
Assignable Input 3 Closed
Class 1
66
Low Fwd Power Trip Active or Latched
Class 1
23
Assignable Input 4 Closed
Class 1
67
Thermal Model Trip Active or Latched
Class 1
24
Assignable Input 5 Closed
Class 1
68
RTD #1 Trip Active or Latched
Class 1
25
Assignable Input 6 Closed
Class 1
69
RTD #2 Trip Active or Latched
Class 1
26
Assignable Input 7 Closed
Class 1
70
RTD #3 Trip Active or Latched
Class 1
27
Trip Coil Supervision - Coil Detected
Class 1
71
RTD #4 Trip Active or Latched
Class 1
28
… Reserved …
72
RTD #5 Trip Active or Latched
Class 1
↓
↓
73
RTD #6 Trip Active or Latched
Class 1
39
… Reserved …
74
RTD #7 Trip Active or Latched
Class 1
40
Assignable Input 1 Trip Active /
Latched
Class 1
75
RTD #8 Trip Active or Latched
Class 1
41
Assignable Input 2 Trip Active /
Latched
Class 1
76
RTD #9 Trip Active or Latched
Class 1
77
RTD #10 Trip Active or Latched
Class 1
42
Assignable Input 3 Trip Active /
Latched
Class 1
78
RTD #11 Trip Active or Latched
Class 1
79
RTD #12 Trip Active or Latched
Class 1
43
Assignable Input 4 Trip Active /
Latched
Class 1
80
Analog Input 1 Trip Active or Latched
Class 1
44
Assignable Input 5 Trip Active /
Latched
Class 1
81
Analog Input 2 Trip Active or Latched
Class 1
82
Analog Input 3 Trip Active or Latched
Class 1
45
Assignable Input 6 Trip Active /
Latched
Class 1
83
Analog Input 4 Trip Active or Latched
Class 1
Assignable Input 7 Trip Active /
Latched
Class 1
84
Loss of Excitation Circle 1 Trip Active
or Latched
Class 1
46
GE Multilin
↓
489 Generator Management Relay
6-43
6
6.5 DNP POINT LISTS
6 COMMUNICATIONS
Table 6–5: BINARY INPUT POINTS (SHEET 3 OF 4)
INDEX
85
86
87
6
Table 6–5: BINARY INPUT POINTS (SHEET 4 OF 4)
DESCRIPTION
EVENT
CLASS
INDEX
DESCRIPTION
EVENT
CLASS
Loss of Excitation Circle 2 Trip Active
or Latched
Class 1
126
RTD #6 Alarm Active or Latched
Class 1
127
RTD #7 Alarm Active or Latched
Ground Directional Trip Active or
Latched
Class 1
Class 1
128
RTD #8 Alarm Active or Latched
Class 1
129
RTD #9 Alarm Active or Latched
Class 1
130
RTD #10 Alarm Active or Latched
Class 1
RTD #11 Alarm Active or Latched
Class 1
Class 1
High Set Phase O/C Trip Active or
Latched
Class 1
88
Distance Zone 1 Trip Active or Latched
Class 1
131
89
Distance Zone 2 Trip Active or Latched
Class 1
132
RTD #12 Alarm Active or Latched
90
… Reserved …
133
Open Sensor Alarm Active or Latched
Class 1
↓
↓
↓
134
Short/Low Temp Alarm Active /
Latched
Class 1
135
Thermal Model Alarm Active or
Latched
Class 1
99
… Reserved …
100
Assignable In 1 Alarm Active / Latched
Class 1
101
Assignable In 2 Alarm Active or
Latched
Class 1
136
Trip Counter Alarm Active or Latched
Class 1
Breaker Failure Alarm Active or
Latched
Class 1
102
Assignable In 3 Alarm Active or
Latched
Class 1
137
103
Assignable In 4 Alarm Active or
Latched
Class 1
138
Trip Coil Monitor Alarm Active /
Latched
Class 1
104
Assignable In 5 Alarm Active or
Latched
Class 1
139
VTFF Alarm Active or Latched
Class 1
140
Current Dmd Alarm Active or Latched
Class 1
105
Assignable In 6 Alarm Active or
Latched
Class 1
141
MW Demand Alarm Active or Latched
Class 1
106
Assignable In 7 Alarm Active / Latched
Class 1
142
Mar Demand Alarm Active or Latched
Class 1
107
Tachometer Alarm Active or Latched
Class 1
143
MVA Alarm Active or Latched
Class 1
108
Overcurrent Alarm Active or Latched
Class 1
144
Analog Input 1 Alarm Active or
Latched
Class 1
109
Neg Seq Alarm Active or Latched
Class 1
145
Ground O/C Alarm Active or Latched
Class 1
Analog Input 2 Alarm Active or
Latched
Class 1
110
111
Undervoltage Alarm Active or Latched
Class 1
146
Class 1
112
Overvoltage Alarm Active or Latched
Class 1
Analog Input 3 Alarm Active or
Latched
113
Volts/Hertz Alarm Active or Latched
Class 1
147
Analog Input 4 Alarm Active or
Latched
Class 1
114
Underfreq Alarm Active or Latched
Class 1
148
Overfrequency Alarm Active or
Latched
Class 1
Not Programmed Alarm Active /
Latched
Class 1
115
149
Neutral O/V (fundamental) Alarm
Active or Latched
Class 1
Simulation Mode Alarm Active or
Latched
Class 1
116
150
Neutral U/V (3rd harm) Alarm Active or
Latched
Class 1
Output Relays Forced Alarm Active or
Latched
Class 1
117
151
Class 1
118
Reactive Power Alarm Active or
Latched
Class 1
Analog Output Forced Alarm Active or
Latched
152
Reverse Power Alarm Active or
Latched
Class 1
Test Switch Shorted Alarm Active or
Latched
Class 1
119
153
Low Fwd Power Alarm Active /
Latched
Class 1
Gnd Directional Alarm Active or
Latched
Class 1
120
121
RTD #1 Alarm Active or Latched
Class 1
122
RTD #2 Alarm Active or Latched
Class 1
123
RTD #3 Alarm Active or Latched
Class 1
124
RTD #4 Alarm Active or Latched
Class 1
125
RTD #5 Alarm Active or Latched
Class 1
154
IRIG-B Failure Alarm Active or Latched
Class 1
155
Generator Running Hour Alarm Active
or Latched
Class 1
Any detected change in the state of any point assigned to Class 1 will cause the generation of an event object.
NOTE
6-44
489 Generator Management Relay
GE Multilin
6 COMMUNICATIONS
6.5 DNP POINT LISTS
6.5.2 BINARY / CONTROL RELAY OUTPUT BLOCK (OBJECTS 10/12)
Table 6–6: BINARY OUTPUT POINT LIST
INDEX
DESCRIPTION
0
Reset
1
Generator Start
2
Generator Stop
3
Clear Trip Counters
4
Clear Last Trip Data
5
Clear MWh and Mvarh
6
Clear Peak Demand Data
7
Clear Generator Information
8
Clear Breaker Information
The following restrictions should be noted when using object 12 to control the points listed in the above table.
1.
The Count field is checked first. If it is zero, the command will be accepted but no action will be taken. If this field is
non-zero, the command will be executed exactly once regardless of its value.
2.
The Control Code field of object 12 is then inspected:
•
The Queue and Clear sub-fields are ignored.
•
If the Control Code field is zero (i.e., NUL operation) the command is accepted but no action is taken.
•
For all points, the only valid control is “Close - Pulse On” (41 hex). This is used to initiate the function (e.g., Reset)
associated with the point.
•
Any value in the Control Code field not specified above is invalid and will be rejected.
3.
The On Time and Off Time fields are ignored. A ”Pulse On” control takes effect immediately when received. Thus, the
timing is irrelevant.
4.
The Status field in the response will reflect the success or failure of the control attempt thus:
•
A Status of “Request Accepted” (0) will be returned if the command was accepted.
•
A Status of “Request not Accepted due to Formatting Errors” (3) will be returned if the Control Code field was incorrectly formatted or an invalid Code was present in the command.
•
A Status of “Control Operation not Supported for this Point” (4) will be returned if an attempt was made to operate the
point and the relay, owing to its configuration, does not allow the point to perform its function.
6
An operate of the Reset point may fail (even if the command is accepted) due to other inputs or conditions (e.g., blocks)
existing at the time. To verify the success or failure of an operate of this point it is necessary that the associated Binary
Input(s) be examined after the control attempt is performed.
When using object 10 to read the status of any Binary Output, a value of zero will always be returned. This is due to the fact
that all points are “Pulse On” and are deemed to be normally off.
GE Multilin
489 Generator Management Relay
6-45
6.5 DNP POINT LISTS
6 COMMUNICATIONS
6.5.3 BINARY / FROZEN COUNTER (OBJECTS 20/21)
Table 6–7: COUNTERS POINT LIST
6
INDEX
ROLLOVER
POINT
DESCRIPTION
0
50,000
1
50,000
Number of Thermal Resets
2
50,000
Number of Trips (total)
3
50,000
Number of Digital Input Trips
4
50,000
Number of Sequential Trips
5
50,000
Number of Field-Breaker Discrepancy Trips
6
50,000
Number of Tachometer Trips
7
50,000
Number of Offline Overcurrent Trips
Number of Breaker Operations
8
50,000
Number of Phase Overcurrent Trips
9
50,000
Number of Negative Sequence Overcurrent Trips
10
50,000
Number of Ground Overcurrent Trips
11
50,000
Number of Phase Differential Trips
12
50,000
Number of Undervoltage Trips
13
50,000
Number of Overvoltage Trips
14
50,000
Number of Volts/Hertz Trips
15
50,000
Number of Phase Reversal Trips
16
50,000
Number of Underfrequency Trips
17
50,000
Number of Overfrequency Trips
18
50,000
Number of Neutral Overvoltage (Fundamental) Trips
19
50,000
Number of Neutral Undervoltage (3rd Harmonic) Trips
20
50,000
Number of Reactive Power Trips
21
50,000
Number of Reverse Power Trips
22
50,000
Number of Underpower Trips
23
50,000
Number of Stator RTD Trips
24
50,000
Number of Bearing RTD Trips
25
50,000
Number of Other RTD Trips
26
50,000
Number of Ambient RTD Trips
27
50,000
Number of Thermal Model Trips
28
50,000
Number of Inadvertent Energization Trips
29
50,000
Number of Analog Input 1 Trips
30
50,000
Number of Analog Input 2 Trips
31
50,000
Number of Analog Input 3 Trips
32
50,000
Number of Analog Input 4 Trips
33
50,000
Number of Loss of Excitation Circle 1 Trips
34
50,000
Number of Loss of Excitation Circle 2 Trips
35
50,000
Number of Ground Directional Trips
36
50,000
Number of High Set Phase Overcurrent Trips
37
50,000
Number of Distance Zone 1 Trips
38
50,000
Number of Distance Zone 2 Trips
NOTE
6-46
The counters cannot be cleared with the Freeze/Clear function codes (9/10). Instead, the control relay output block
points can be used to clear groups of counters. There is only one copy of each counter, so clearing a counter via
Modbus or the front panel display causes the corresponding DNP counter point to be cleared and vice-versa.
489 Generator Management Relay
GE Multilin
6 COMMUNICATIONS
6.5 DNP POINT LISTS
6.5.4 ANALOG INPUT / INPUT CHANGE (OBJECTS 30/32)
In the following table, the Format column indicates that the associated data point format is determined by the entry in Table
6–2: Data Formats on page 6–34. For example, an “F1” format is described in that table as a (16-bit) unsigned value without any decimal places. Therefore, the value read should be interpreted in this manner. Many of the values reported by the
489 have a size of 32-bits and have had their upper and lower 16-bit components assigned to separate points. Where indicated, refer to the appropriate note following the table for more detail.
Table 6–8: ANALOG INPUTS POINT LIST (SHEET 1 OF 4)
INDEX
FORMAT
0
F133
1
F1
2
F1
3
4
DESCRIPTION
EVENT CLASS
ASSIGNED TO
NOTES
Generator Status
Class 1
Note 3
Generator Thermal Capacity Used
Class 1
Estimated Trip Time On Overload (seconds, 65535 means never)
Class 1
F134
Cause Of Last Trip
Class 1
Note 3
F19
Time Of Last Trip (Upper 16 Bits)
Class 1
Notes 3,4
5
F19
Time Of Last Trip (Lower 16 Bits)
Class 1
Notes 3,4
6
F18
Date Of Last Trip (Upper 16 Bits)
Class 1
Notes 3,4
7
F18
Date Of Last Trip (Lower 16 Bits)
Class 1
Notes 3,4
8
F1
Tachometer Pre-Trip
Class 1
Note 3
9
F1
Scale factor for pre-trip current readings (pre-trip points marked with
“Note 6”). Will always be a power of 10 (1, 10, 100, etc.). Changes only
when the configuration setpoints are changed.
Class 1
Note 3
10
F1
Phase A Pre-Trip Current
Class 1
Notes 3, 6
11
F1
Phase B Pre-Trip Current
Class 1
Notes 3, 6
12
F1
Phase C Pre-Trip Current
Class 1
Notes 3, 6
13
F1
Phase A Pre-Trip Differential Current
Class 1
Notes 3, 6
14
F1
Phase B Pre-Trip Differential Current
Class 1
Notes 3, 6
15
F1
Phase C Pre-Trip Differential Current
Class 1
Notes 3, 6
16
F1
Pre-Trip Negative Sequence Current
Class 1
Note 3
17
F1
Ground Current Scale Factor. Will always be a power of 10 (1, 10, 100,
etc.). Changes only when the configuration setpoints are changed.
Class 1
Note 3
18
F6
Pre-Trip Ground Current (scaled according to previous setpoint)
Class 1
Note 3
19
F1
Phase A-B Pre-Trip Voltage
Class 1
Note 3
20
F1
Phase B-C Pre-Trip Voltage
Class 1
Note 3
21
F1
Phase C-A Pre-Trip Voltage
Class 1
Note 3
22
F3
Pre-Trip Frequency
Class 1
Note 3
23
F1
Pre-Trip Real Power (MW)
Class 1
Notes 3,8
24
F1
Pre-Trip Real Power (kW)
Class 1
Notes 3,8
25
F1
Pre-Trip Reactive Power (Mar
Class 1
Notes 3,8
26
F1
Pre-Trip Reactive Power (kvar)
Class 1
Notes 3,8
27
F1
Pre-Trip Apparent Power (MVA)
Class 1
Notes 3,8
28
F1
Pre-Trip Apparent Power (kVA)
Class 1
Notes 3,8
29
F1
Last Trip Stator RTD
Class 1
Note 3
30
F4
Last Trip Hottest Stator RTD Temperature (°C)
Class 1
Note 3
Note 3
31
F1
Last Trip Bearing RTD
Class 1
32
F4
Last Trip Hottest Bearing RTD Temperature (°C)
Class 1
Note 3
33
F1
Last Trip Other RTD
Class 1
Note 3
34
F4
Last Trip Hottest Other RTD Temperature (°C)
Class 1
Note 3
Note 3
35
F1
Last Trip Ambient RTD
Class 1
36
F4
Last Trip Hottest Ambient RTD Temperature (°C)
Class 1
Note 3
37
F12
Pre-Trip Analog Input 1
Class 1
Notes 3,9
GE Multilin
489 Generator Management Relay
6
6-47
6.5 DNP POINT LISTS
6 COMMUNICATIONS
Table 6–8: ANALOG INPUTS POINT LIST (SHEET 2 OF 4)
6
INDEX
FORMAT
38
F12
39
F12
40
41
DESCRIPTION
EVENT CLASS
ASSIGNED TO
NOTES
Pre-Trip Analog Input 2
Class 1
Notes 3,9
Pre-Trip Analog Input 3
Class 1
Notes 3,9
F12
Pre-Trip Analog Input 4
Class 1
Notes 3,9
F1
Pre-Trip Fundamental Frequency Neutral Voltage (volts)
Class 1
Notes 3,10
42
F10
Pre-Trip Fundamental Frequency Neutral Voltage (tenths of a volt)
Class 1
Notes 3,10
43
F1
Pre-Trip Third Harmonic Neutral Voltage (volts)
Class 1
Notes 3,10
44
F10
Pre-Trip Third Harmonic Neutral Voltage (tenths of a volt)
Class 1
Notes 3,10
45
F2
Pre-Trip Vab/Iab (loss of excitation impedance)
Class 1
Note 3
46
F1
Pre-Trip Vab/Iab Angle (loss of excitation impedance angle)
Class 1
Note 3
47
F1
Scale factor for current readings (points marked with “Note 7”). Will
always be a power of 10 (1, 10, 100, etc.). Changes only when the
configuration setpoints are changed.
Class 1
Note 3
48
F1
Phase A Output Current
Class 2
Note 7
49
F1
Phase B Output Current
Class 2
Note 7
50
F1
Phase C Output Current
Class 2
Note 7
51
F1
Phase A Neutral-Side Current
Class 2
Note 7
52
F1
Phase B Neutral-Side Current
Class 2
Note 7
53
F1
Phase C Neutral-Side Current
Class 2
Note 7
54
F1
Phase A Differential Current
Class 2
Note 7
55
F1
Phase B Differential Current
Class 2
Note 7
56
F1
Phase C Differential Current
Class 2
Note 7
57
F1
Average Phase Current
Class 2
Note 7
58
F1
Generator Load (percent)
Class 2
59
F1
Negative Sequence Current
Class 2
60
F1
Ground Current Scale Factor. Will always be a power of 10 (1, 10, 100,
etc.). Changes only when the configuration setpoints are changed.
Class 1
61
F3
Ground Current (scaled according to the previous point)
Class 2
62
F1
Phase A-B Voltage
Class 2
63
F1
Phase B-C Voltage
Class 2
64
F1
Phase C-A Voltage
Class 2
65
F1
Average Line Voltage
Class 2
66
F1
Phase A-N Voltage
Class 2
67
F1
Phase B-N Voltage
Class 2
68
F1
Phase C-N Voltage
Class 2
69
F1
Average Phase Voltage
Class 2
70
F3
Per Unit Measurement Of V/Hz
Class 2
71
F3
Frequency
Class 2
Note 3
Note 2
72
F1
Fundamental Frequency Neutral Voltage (volts)
Class 2
Note 10
73
F10
Fundamental Frequency Neutral Voltage (tenths of a volt)
Class 2
Note 10
74
F1
Third Harmonic Neutral Voltage (volts)
Class 2
Note 10
75
F10
Third Harmonic Neutral Voltage (tenths of a volt)
Class 2
Note 10
76
F1
Third Harmonic Terminal Voltage (volts)
Class 2
Note 10
77
F10
Third Harmonic Terminal Voltage (tenths of a volt)
Class 2
Note 10
78
F2
Vab/Iab (loss of excitation impedance)
Class 2
79
F1
Vab/Iab Angle (loss of excitation impedance angle)
Class 2
80
F6
Power Factor
Class 2
81
F1
Real Power (MW)
Class 2
Note 8
82
F1
Real Power (kW)
Class 2
Note 8
6-48
489 Generator Management Relay
GE Multilin
6 COMMUNICATIONS
6.5 DNP POINT LISTS
Table 6–8: ANALOG INPUTS POINT LIST (SHEET 3 OF 4)
INDEX
FORMAT
83
F1
84
F1
85
86
DESCRIPTION
EVENT CLASS
ASSIGNED TO
NOTES
Reactive Power (Mar)
Class 2
Note 8
Reactive Power (kvar)
Class 2
Note 8
F1
Apparent Power (MVA)
Class 2
Note 8
F1
Apparent Power (kVA)
Class 2
Note 8
87
F1
Hottest Stator RTD
Class 2
Note 3
88
F4
Hottest Stator RTD Temperature (°C)
Class 2
89
F4
RTD #1 Temperature (°C)
Class 2
90
F4
RTD #2 Temperature (°C)
Class 2
91
F4
RTD #3 Temperature (°C)
Class 2
92
F4
RTD #4 Temperature (°C)
Class 2
93
F4
RTD #5 Temperature (°C)
Class 2
94
F4
RTD #6 Temperature (°C)
Class 2
95
F4
RTD #7 Temperature (°C)
Class 2
96
F4
RTD #8 Temperature (°C)
Class 2
97
F4
RTD #9 Temperature (°C)
Class 2
98
F4
RTD #10 Temperature (°C)
Class 2
99
F4
RTD #11 Temperature (°C)
Class 2
100
F4
RTD #12 Temperature (°C)
Class 2
101
F1
Current Demand
Class 2
Note 7
102
F1
MW Demand
Class 2
Note 8
103
F1
kW Demand
Class 2
Note 8
104
F1
Mvar Demand
Class 2
Note 8
105
F1
kvar Demand
Class 2
Note 8
106
F1
MVA Demand
Class 2
Note 8
107
F1
kVA Demand
Class 2
Note 8
108
F1
Peak Current Demand
Class 2
Note 7
109
F1
Peak MW Demand
Class 2
Note 8
110
F1
Peak kW Demand
Class 2
Note 8
111
F1
Peak Mvar Demand
Class 2
Note 8
112
F1
Peak kvar Demand
Class 2
Note 8
113
F1
Peak MVA Demand
Class 2
Note 8
114
F1
Peak kVA Demand
Class 2
Note 8
115
F12
Analog Input 1
Class 2
Note 9
116
F12
Analog Input 2
Class 2
Note 9
117
F12
Analog Input 3
Class 2
Note 9
118
F12
Analog Input 4
Class 2
Note 9
119
F1
Tachometer RPM
Class 2
120
F1
Average Generator Load
Class 2
121
F1
Average Negative Sequence Current
Class 2
122
F1
Average Phase-Phase Voltage
Class 2
123
-
User Map Value 1
Note 5
124
-
User Map Value 2
Note 5
↓
↓
…↓...
246
-
User Map Value 124
247
-
User Map Value 125
248
F118
Active Setpoint Group
Class 1
249
F13
Positive kWh
Class 2
GE Multilin
↓
6
↓
Note 5
Note 5
489 Generator Management Relay
Note 3
6-49
6.5 DNP POINT LISTS
6 COMMUNICATIONS
Table 6–8: ANALOG INPUTS POINT LIST (SHEET 4 OF 4)
INDEX
FORMAT
DESCRIPTION
EVENT CLASS
ASSIGNED TO
250
F13
Positive kvarh
Class 2
251
F13
Negative kvarh
Class 2
252
F12
Generator Hours Online
Class 2
NOTES
TABLE NOTES:
6
1.
Unless otherwise specified, an event object will be generated for a point if the current value of the point changes by an
amount greater than or equal to two percent of its previous value.
2.
An event object is created for the Frequency point if the frequency changes by 0.04 Hz or more from its previous value.
3.
An event object is created for these points if the current value of a point is in any way changed from its previous value.
4.
To support existing SCADA hardware that is not capable of 32-bit data reads, the upper and lower 16-bit portions of
these 32-bit values have been assigned to separate points. To read this data, it is necessary to read both the upper
and lower 16-bit portions, concatenate these two values to form a 32-bit value and interpret the result in the format
associated with the point as specified in Table 6–2: Data Formats on page 6–34.
5.
The data returned by a read of the User Map Value points is determined by the values programmed into the corresponding User Map Address registers (which are only accessible via Modbus). Refer to Section 6.3.2: User-Definable
Memory Map Area on page 6–8 for more information. Changes in User Map Value points never generate event
objects. Note that it is possible to refer to a 32-bit quantity in a user map register, which may require the use of a 32-bit
variation to read the associated analog input point.
6.
The scale for pre-trip currents is determined by the value in point 9, which should not normally change
7.
The scale for currents is determined by the value in point 47, which should not normally change
8.
Each power quantity is available at two different points, with two different scale factors (kW and MW, for example). The
user should select the unit which is closest to providing the resolution and range desired. If 32-bit analog input capability is present, the higher-resolution (kW, kvar, kVA) points should generally be used, since they provide the greatest
resolution.
9.
Analog input values may be –50000 to +50000 if so configured. Therefore, 32-bit analog input capability is required to
read the full possible range. If the SCADA equipment can only read 16-bit registers, the analog inputs should be configured to operate within the range –32768 to +32767.
10. Each neutral voltage quantity is available at two different points, with two different scale factors (volts and tenths of a
volt). The user should select the unit which is closest to providing the resolution and range desired. If 32-bit analog
input capability is present, the higher-resolution (tenths of a volt) points should generally be used, since they provide
the greatest resolution.
6-50
489 Generator Management Relay
GE Multilin
7 TESTING
7.1 TEST SETUP
7 TESTING 7.1TEST SETUP
7.1.1 DESCRIPTION
The purpose of this testing description is to demonstrate the procedures necessary to perform a complete functional test of
all the 489 hardware while also testing firmware/hardware interaction in the process. Since the 489 is packaged in a drawout case, a demo case (metal carry case in which the 489 may be mounted) may be useful for creating a portable test set
with a wiring harness for all of the inputs and outputs. Testing of the relay during commissioning using a primary injection
test set will ensure that CTs and wiring are correct and complete.
The 489 tests are listed below. For the following tests refer to Figure 7–1: Secondary Current Injection Testing on page 7–2:
1.
Output Current Accuracy Test
2.
Phase Voltage Input Accuracy Test
3.
Ground, Neutral, and Differential Current Accuracy Test
4.
Neutral Voltage (Fundamental) Accuracy Test
5.
Negative Sequence Current Accuracy Test
6.
RTD Accuracy Test
7.
Digital Input and Trip Coil Supervision Accuracy Test
8.
Analog Input and Outputs Test
9.
Output Relay Test
10. Overload Curve Test
11. Power Measurement Test
12. Reactive Power Test
13. Voltage Phase Reversal Test
For the following tests refer to Figure 7–2: Secondary Injection Setup #2 on page 7–12:
14. GE Multilin (HGF) Ground Current Accuracy Test
15. Neutral Voltage (3rd Harmonic) Accuracy Test
16. Phase Differential Trip Test
For the following test refer to Figure 7–3: Secondary Injection Test Setup #3 on page 7–15:
17. Voltage Restrained Overcurrent Test
7
GE Multilin
489 Generator Management Relay
7-1
7.1 TEST SETUP
7 TESTING
7.1.2 SECONDARY CURRENT INJECTION TEST SETUP
VC
3 PHASE VARIABLE AC TEST SET
VA
IN
VB
IA
GROUND INPUTS
IC
PHASE A PHASE B PHASE C
NEUTRAL END CT's
OUTPUT CT's
Vc
PHASE
VOLTAGE INPUTS
H12
CONTROL
POWER
H11
FILTER GROUND
B1
RTD SHIELD
A1
HOT
A2
COMPENSATION
A3
RTD RETURN
A4
COMPENSATION
A5
HOT
A6
HOT
A7
COMPENSATION
A8
RTD RETURN
A9
COMPENSATION
E12
IRIG - B
F12
TRIP COIL
SUPERVISION
RTD #3
500 Ohms
A10
HOT
A11
HOT
F11
A12
COMPENSATION
RTD RETURN
F3
A14
COMPENSATION
E5
500 Ohms
R2 AUXILIARY
R3 AUXILIARY
500 Ohms
D2
COMPENSATION
RTD RETURN
D4
COMPENSATION
D5
HOT
D6
HOT
500 Ohms
F5
R4 AUXILIARY
R5 ALARM
COMPENSATION
E7
RTD RETURN
F8
D9
COMPENSATION
D10
HOT
D11
HOT
R6 SERVICE
RTD #10
TIMER
G
R
G
F7
D7
G
G
E9
F9
500 Ohms
R
F6
D8
500 Ohms
G
E6
E8
RTD #9
G
F4
RTD #8
500 Ohms
R
E4
RTD #7
D3
R
START
TRIGGER
E3
RTD #6
HOT
HOT
STOP
TRIGGER
E1
F2
A13
D1
SWITCH
COMMON
F1
RTD #5
A15
SWITCH
+24VAC
E11
E2
R1 TRIP
RTD #4
500 Ohms
R
RTD #11
D12
COMPENSATION
D13
RTD RETURN
D14
COMPENSATION
D15
HOT
500 Ohms
RTD #12
C3
C4
BREAKER
STATUS
COMPUTER
COMM.
RS485
AUXILIARY
RS485
D25 D26 D27 B2
B3
ANALOG I/O
ANALOG OUTPUTS
ANALOG INPUTS
4+
COM
ACCESS
C2
3+
SWITCH +24Vdc
C1
1+
COMMON
D24
2+
ASSIGNABLE INPUT 7
D23
+24
VDC
ASSIGNABLE INPUT 6
SHIELD
D21
D22
4+
ASSIGNABLE INPUT 4
ASSIGNABLE INPUT 5
GE Multilin
SECONDARY INJECTION
TEST SETUP
3+
D19
D20
g
1+
ASSIGNABLE INPUT 3
2+
D18
COM
ASSIGNABLE INPUT 2
COM
ASSIGNABLE INPUT 1
D17
COM
D16
DIGITAL INPUTS
V
SAFETY GROUND G12
RTD #2
500 Ohms
7
G11
RTD #1
500 Ohms
RTD
SIMULATION
RESISTORS
OR RESISTANCE
DECADE BOX
Vcom
Va
Vb
COM
COM
1A/5A
COM
1A/5A
1A/5A
AUTOMATIC CT
SHORTING
BAR
PHASE a PHASE b PHASE c
500 Ohms
START
VA VB VC VN
G6 H6 G7 H7 G8 H8 G2 H1 H2 G1
COM
COM
1A/5A
COM
1A/5A
1A/5A
HGF
COM
1A
COM
V
NEUTRAL
E10 F10 G9 H9 G10 H10 G3 H3 G4 H4 G5 H5
IB
B4 A16 A17 A18 A19 A20 A21 A22 A23 A24 A25 A26 A27
A
A
RS485
RS485
V
A
A
808818A3.CDR
Figure 7–1: SECONDARY CURRENT INJECTION TESTING
7-2
489 Generator Management Relay
GE Multilin
7 TESTING
7.2 HARDWARE FUNCTIONAL TESTS
7.2HARDWARE FUNCTIONAL TESTS
7.2.1 OUTPUT CURRENT ACCURACY
The specification for output and neutral end current input is ±0.5% of 2 × CT when the injected current is less than 2 × CT.
Perform the steps below to verify accuracy.
1.
Alter the following setpoint:
S2 SYSTEM SETUP  CURRENT SENSING  PHASE CT PRIMARY: "1000
2.
A"
Measured values should be ±10 A. Inject the values shown in the table below and verify accuracy of the measured values. View the measured values in:
A2 METERING DATA  CURRENT METERING
INJECTED CURRENT
EXPECTED
CURRENT
1 A UNIT
5 A UNIT
0.1 A
0.5 A
100 A
0.2 A
1.0 A
200 A
0.5 A
2.5 A
500 A
1A
5A
1000 A
1.5 A
7.5 A
1500 A
2A
10 A
2000 A
MEASURED CURRENT
PHASE A
PHASE B
PHASE C
7.2.2 PHASE VOLTAGE INPUT ACCURACY
The specification for phase voltage input accuracy is ±0.5% of full scale (200 V). Perform the steps below to verify accuracy.
1.
Alter the following setpoints:
S2 SYSTEM SETUP  VOLTAGE SENSING  VT CONNECTION TYPE: "Wye"
S2 SYSTEM SETUP  VOLTAGE SENSING  VOLTAGE TRANSFORMER RATIO:
2.
"10.00:1"
Measured values should be ±1.0 V. Apply the voltage values shown in the table and verify accuracy of the measured
values. View the measured values in:
A2 METERING DATA  VOLTAGE METERING
APPLIED LINENEUTRAL VOLTAGE
EXPECTED VOLTAGE
READING
30 V
300 V
50 V
500 V
100 V
1000 V
150 V
1500 V
200 V
2000 V
270 V
2700 V
GE Multilin
MEASURED VOLTAGE
A-N
489 Generator Management Relay
B-N
7
C-N
7-3
7.2 HARDWARE FUNCTIONAL TESTS
7 TESTING
7.2.3 GROUND (1 A), NEUTRAL, AND DIFFERENTIAL CURRENT ACCURACY
The specification for neutral, differential and 1 A ground current input accuracy is ±0.5% of 2 × CT. Perform the steps below
to verify accuracy.
1.
Alter the following setpoints:
S2 SYSTEM SETUP  CURRENT SENSING  GROUND CT: "1A Secondary"
S2 SYSTEM SETUP  CURRENT SENSING  GROUND CT RATIO: "1000:1"
S2 SYSTEM SETUP  CURRENT SENSING  PHASE CT PRIMARY: "1000 A"
S5 CURRENT ELEMENTS  PHASE DIFFERENTIAL  PHASE DIFFERENTIAL TRIP: "Unlatched"
S5 CURRENT ELEMENTS  PHASE DIFFERENTIAL  DIFFERENTIAL TRIP MIN. PICKUP: "0.1 x
CT"
2.
Note: the last two setpoints are needed to view the neutral and the differential current. The trip element will operate
when differential current exceeds 100 A.
3.
Measured values should be ±10 A. Inject (IA only) the values shown in the table below into one phase only and verify
accuracy of the measured values. View the measured values in:
A2 METERING DATA  CURRENT METERING
or press the
NEXT
key to view the current values when differential trip element is active.
Table 7–1: NEUTRAL AND GROUND CURRENT TEST RESULTS
INJECTED
CURRENT
1 A UNIT
EXPECTED
CURRENT
READING
0.1 A
100 A
0.2 A
200 A
0.5 A
500 A
1A
1000 A
MEASURED
GROUND
CURRENT
MEASURED NEUTRAL CURRENT
PHASE A
PHASE B
PHASE C
Table 7–2: DIFFERENTIAL CURRENT TEST RESULTS
INJECTED
CURRENT
0.1 A
7
EXPECTED CURRENT READING
DIFF. PHASE A
DIFF PHASE B,C
200 A
100 A
0.2 A
400 A
200 A
0.5 A
1000 A
500 A
1A
2000 A
1000 A
MEASURED DIFFERENTIAL CURRENT
PHASE A
PHASE B
PHASE C
7.2.4 NEUTRAL VOLTAGE (FUNDAMENTAL) ACCURACY
The specification for neutral voltage (fundamental) accuracy is ±0.5% of full scale (100 V). Perform the steps below to verify
accuracy.
1.
Alter the following setpoints:
S2 SYSTEM SETUP  VOLTAGE SENSING  NEUTRAL VOLTAGE TRANSFORMER: "Yes"
S2 SYSTEM SETUP  VOLTAGE SENSING  NEUTRAL V.T. RATIO: "10.00:1"
S2 SYSTEM SETUP  GEN. PARAMETERS  GENERATOR NOMINAL FREQUENCY: "60 Hz"
2.
Measured values should be ±5.0 V. Apply the voltage values shown in the table and verify accuracy of the measured
values. View the measured values in:
A2 METERING DATA  VOLTAGE METERING
7-4
APPLIED NEUTRAL
VOLTAGE AT 60 HZ
EXPECTED NEUTRAL
VOLTAGE
10 V
100 V
30 V
300 V
50 V
500 V
MEASURED NEUTRAL
VOLTAGE
489 Generator Management Relay
GE Multilin
7 TESTING
7.2 HARDWARE FUNCTIONAL TESTS
7.2.5 NEGATIVE SEQUENCE CURRENT ACCURACY
The 489 measures negative sequence current as a percent of Full Load Amperes (FLA). A sample calculation of negative
sequence current is shown below. Given the following generator parameters:
Rated MVA (PA) = 1.04
Voltage Phase to Phase (Vpp): 600 V
6
PA
1.04 × 10
we have: FLA = ----------------------- = --------------------------- = 1000 A
3 × V pp
3 × 600
(EQ 7.1)
With the following output currents:
I a = 780 ∠0°,
I b = 1000 ∠113° lag,
I c = 1000 ∠247° lag
(EQ 7.2)
The negative-sequence current Ins is calculated as:
1
2
I ns = --- ( I a + a I b + aI c ) where a = 1 ∠120° = – 0.5 + j0.866
3
1
2
= --- ( 780 ∠0° + ( 1 ∠120° ) ( 1000 ∠– 113° ) + ( 1 ∠120° ) ( 1000 ∠113° ) )
3
1
1
= --- ( 780 ∠0° + 1000 ∠127° + 1000 ∠233° ) = --- ( 780 – 601.8 + j798.6 – 601.8 – j798.6 )
3
3
= – 141.2
I ns
 %I ns = ----------- × 100 = 14%
FLA
(EQ 7.3)
Therefore, the negative sequence current is 14% of FLA. The specification for negative sequence current accuracy is per
output current inputs. Perform the steps below to verify accuracy.
1.
Alter the following setpoints:
S2 SYSTEM SETUP  GENERATOR PARAMETER  GENERATOR RATED MVA: "1.04"
S2 SYSTEM SETUP  GENERATOR PARAMETER  VOLTAGE PHASE-PHASE: "600"
(Note: This is equivalent to setting FLA = 1000 A – For testing purposes ONLY!)
"1000 A"
S2 SYSTEM SETUP  CURRENT SENSING  PHASE CT PRIMARY:
2.
Inject the values shown in the table below and verify accuracy of the measured values. View the measured values in:
A2 METERING DATA  CURRENT METERING
INJECTED CURRENT
7
EXPECTED NEGATIVE SEQUENCE
CURRENT LEVEL
1 A UNIT
5 A UNIT
Ia = 0.78 A ∠0°
Ib = 1 A ∠113° lag
Ic = 1 A ∠247° lag
Ia = 3.9 A ∠0°
Ib = 5 A ∠113° lag
Ic = 5 A ∠247° lag
14% FLA
Ia = 1.56 A ∠0°
Ib = 2 A ∠113° lag
Ic = 2 A ∠247° lag
Ia = 7.8 A ∠0°
Ib = 10 A ∠113° lag
Ic = 10 A ∠247° lag
28% FLA
Ia = 0.39 A ∠0°
Ib = 0.5 A ∠113° lag
Ic = 0.5 A ∠247° lag
Ia = 1.95 A ∠0°
Ib = 2.5 A ∠113° lag
Ic = 2.5 A ∠247° lag
7% FLA
GE Multilin
489 Generator Management Relay
MEASURED NEGATIVE SEQUENCE
CURRENT LEVEL
7-5
7.2 HARDWARE FUNCTIONAL TESTS
7 TESTING
7.2.6 RTD ACCURACY
The specification for RTD input accuracy is ±2° for Platinum/Nickel and ±5° for Copper. Perform the steps below.
1.
Alter the following setpoints:
S8 RTD TEMPERATURE  RTD TYPE  STATOR RTD TYPE: "100 Ohm Platinum" (select desired
S8 RTD TEMPERATURE  RTD #1  RTD #1 APPLICATION: "Stator" (repeat for RTDs 2 to 12)
Measured values should be ±2°C / ±4°F for platinum/nickel and ±5°C / ±9°F for copper. Alter the resistance applied to
the RTD inputs as shown below to simulate RTDs and verify accuracy. View the measured values in A2 METERING DATA
 TEMPERATURE.
2.
APPLIED
RESISTANCE
100 Ω PLATINUM
84.27 Ω
°C
°F
–40°C
–40°F
0°C
32°F
119.39 Ω
50°C
122°F
138.50 Ω
100°C
212°F
157.32 Ω
150°C
302°F
175.84 Ω
200°C
392°F
194.08 Ω
250°C
482°F
92.76 Ω
°C
°F
–40°C
–40°F
0°C
32°F
157.74 Ω
50°C
122°F
200.64 Ω
100°C
212°F
248.95 Ω
150°C
302°F
303.46 Ω
200°C
392°F
366.53 Ω
250°C
482°F
77.30 Ω
°C
°F
–40°C
–40°F
0°C
32°F
131.45 Ω
50°C
122°F
167.20 Ω
100°C
212°F
207.45 Ω
150°C
302°F
252.88 Ω
200°C
392°F
305.44 Ω
250°C
482°F
7.49 Ω
1
2
3
4
1
2
3
4
°C
°F
–40°F
9.04 Ω
0°C
32°F
10.97 Ω
50°C
122°F
12.90 Ω
100°C
212°F
14.83 Ω
150°C
302°F
16.78 Ω
200°C
392°F
18.73 Ω
250°C
482°F
6
7
8
9
10
11
12
5
6
7
8
9
10
11
12
10
11
12
10
11
12
MEASURED RTD TEMPEATURE
SELECT ONE: ____°C ____°F
1
2
3
4
EXPECTED RTD
TEMPERATURE READING
–40°C
5
MEASURED RTD TEMPEATURE
SELECT ONE: ____°C ____°F
EXPECTED RTD
TEMPERATURE READING
100.00 Ω
APPLIED
RESISTANCE
10 Ω COPPER
MEASURED RTD TEMPEATURE
SELECT ONE: ____°C ____°F
EXPECTED RTD
TEMPERATURE READING
120.00 Ω
APPLIED
RESISTANCE
100 Ω NICKEL
7-6
EXPECTED RTD
TEMPERATURE READING
100.00 Ω
APPLIED
RESISTANCE
120 Ω NICKEL
7
type)
5
6
7
8
9
MEASURED RTD TEMPEATURE
SELECT ONE: ____°C ____°F
1
2
3
4
5
489 Generator Management Relay
6
7
8
9
GE Multilin
7 TESTING
7.2 HARDWARE FUNCTIONAL TESTS
7.2.7 DIGITAL INPUTS AND TRIP COIL SUPERVISION
The digital inputs and trip coil supervision can be verified easily with a simple switch or pushbutton. Verify the SWITCH
+24 V DC with a voltmeter. Perform the steps below to verify functionality of the digital inputs.
1.
Open switches of all of the digital inputs and the trip coil supervision circuit.
2.
View the status of the digital inputs and trip coil supervision in:
A1 STATUS  DIGITAL INPUTS
3.
Close switches of all of the digital inputs and the trip coil supervision circuit.
4.
View the status of the digital inputs and trip coil supervision in:
A1 STATUS  DIGITAL INPUTS
INPUT
EXPECTED STATUS
(SWITCH OPEN)
 PASS
 FAIL
EXPECTED STATUS
(SWITCH CLOSED)
ACCESS
Open
Shorted
BREAKER STATUS
Open
Shorted
ASSIGNABLE INPUT 1
Open
Shorted
ASSIGNABLE INPUT 2
Open
Shorted
ASSIGNABLE INPUT 3
Open
Shorted
ASSIGNABLE INPUT 4
Open
Shorted
ASSIGNABLE INPUT 5
Open
Shorted
ASSIGNABLE INPUT 6
Open
Shorted
ASSIGNABLE INPUT 7
Open
Shorted
No Coil
Coil
TRIP COIL SUPERVISION
 PASS
 FAIL
7.2.8 ANALOG INPUTS AND OUTPUTS
The specification for analog input and analog output accuracy is ±1% of full scale. Perform the steps below to verify accuracy. Verify the Analog Input +24 V DC with a voltmeter.
4 to 20 mA INPUTS:
1.
Alter the following setpoints:
S11 ANALOG I/O  ANALOG INPUT1  ANALOG INPUT1: "4-20 mA"
S11 ANALOG I/O  ANALOG INPUT1  ANALOG INPUT1 MINIMUM: "0"
S11 ANALOG I/O  ANALOG INPUT1  ANALOG INPUT1 MAXIMUM: "1000"
2.
Analog output values should be ±0.2 mA on the ammeter. Measured analog input values should be ±10 units. Force
the analog outputs using the following setpoints:
S12 TESTING  TEST ANALOG OUTPUT  FORCE ANALOG OUTPUTS FUNCTION: "Enabled"
S12 TESTING  TEST ANALOG OUTPUT  ANALOG OUTPUT 1 FORCED VALUE: "0%" (enter
3.
7
(repeat all for Analog Inputs 2 to 4)
%, repeat for Outputs 2 to 4)
Verify the ammeter readings and the measured analog input readings. For the purposes of testing, the analog input is
fed in from the analog output (see Figure 7–1: Secondary Current Injection Testing). View the measured values in:
A2 METERING DATA  ANALOG INPUTS
ANALOG
OUTPUT
FORCE
VALUE
EXPECTED
AMMETER
READING
0%
4 mA
0 units
25%
8 mA
250 units
50%
12 mA
500 units
75%
16 mA
750 units
100%
20 mA
1000 units
GE Multilin
MEASURED AMMETER READING
(MA)
1
2
3
4
EXPECTED
ANALOG INPUT
READING
489 Generator Management Relay
MEASURED ANALOG INPUT
READING (UNITS)
1
2
3
4
7-7
7.2 HARDWARE FUNCTIONAL TESTS
7 TESTING
0 to 1 mA ANALOG INPUTS:
1.
Alter the following setpoints:
S11 ANALOG I/O  ANALOG INPUT1  ANALOG INPUT1: "0-1 mA"
S11 ANALOG I/O  ANALOG INPUT1  ANALOG INPUT1 MINIMUM: "0"
S11 ANALOG I/O  ANALOG INPUT1  ANALOG INPUT1 MAXIMUM: "1000"
(repeat for Analog Inputs 2 to 4)
Analog output values should be ±0.01 mA on the ammeter. Measured analog input values should be ±10 units. Force
the analog outputs using the following setpoints:
2.
S12 TESTING  TEST ANALOG OUTPUT  FORCE ANALOG OUTPUTS FUNCTION: "Enabled"
S12 TESTING  TEST ANALOG OUTPUT  ANALOG OUTPUT 1 FORCED VALUE: "0%" (enter
%, repeat for Outputs 2 to 4)
Verify the ammeter readings as well as the measured analog input readings. View the measured values in:
A2 METERING DATA  ANALOG INPUTS
ANALOG
OUTPUT
FORCE
VALUE
EXPECTED
AMMETER
READING
MEASURED AMMETER READING
(MA)
1
2
3
4
EXPECTED
ANALOG INPUT
READING
0%
0 mA
0 units
25%
0.25 mA
250 units
50%
0.50 mA
500 units
75%
0.75 mA
750 units
100%
1.00 mA
1000 units
MEASURED ANALOG INPUT
READING (UNITS)
1
2
3
4
7.2.9 OUTPUT RELAYS
To verify the functionality of the output relays, perform the following steps:
1.
Using the setpoint:
S12 TESTING  TEST OUTPUT RELAYS  FORCE OPERATION OF RELAYS: "R1
Trip"
select and store values as per the table below, verifying operation
FORCE
OPERATION
SETPOINT
7
EXPECTED MEASUREMENT
( FOR SHORT)
R1
NO
R1 Trip
NC
R2
NO

NC
R3
NO

NC
R4
NO
NC












R4 Auxiliary



R5 Alarm




R6 Service




No Relays





NO



R6
NC

R3 Auxiliary
All Relays
R5
NO

R2 Auxiliary

ACTUAL MEASUREMENT
( FOR SHORT)




R1
NO
NC
R2
NO
NC
R3
NO
NC
R4
NO
NC
R5
NO
R6
NC
NO
NC





NC



The R6 Service relay is failsafe or energized normally. Operating R6 causes it to de-energize.
NOTE
7-8
489 Generator Management Relay
GE Multilin
7 TESTING
7.3 ADDITIONAL FUNCTIONAL TESTS
7.3ADDITIONAL FUNCTIONAL TESTS
7.3.1 OVERLOAD CURVE ACCURACY
The specification for overload curve timing accuracy is ±100 ms or ±2% of time to trip. Pickup accuracy is as per the current
inputs (±0.5% of 2 × CT when the injected current is less than 2 × CT and ±1% of 20 × CT when the injected current is equal
to or greater than 2 × CT). Perform the steps below to verify accuracy.
1.
Alter the following setpoints:
S2 SYSTEM SETUP  GEN. PARAMETERS  GENERATOR RATED MVA: "1.04"
S2 SYSTEM SETUP  GEN. PARAMETERS  GENERATOR VOLTAGE PHASE-PHASE: "600"
(Note: This is equivalent to setting FLA = 1000 A – For testing purposes ONLY!)
S2 SYSTEM SETUP  CURRENT SENSING  PHASE CT PRIMARY: "1000"
S9 THERMAL MODEL  MODEL SETUP  SELECT CURVE STYLE: "Standard"
S9 THERMAL MODEL  MODEL SETUP  OVERLOAD PICKUP LEVEL: "1.10 x FLA"
S9 THERMAL MODEL  MODEL SETUP  UNBALANCE BIAS K FACTOR: "0"
S9 THERMAL MODEL  MODEL SETUP  HOT/COLD SAFE STALL RATIO: "1.00"
S9 THERMAL MODEL  MODEL SETUP  ENABLE RTD BIASING: "No"
S9 THERMAL MODEL  MODEL SETUP  STANDARD OVERLOAD CURVE NUMBER: "4"
S9 THERMAL MODEL  MODEL SETUP  ENABLE THERMAL MODEL: "Yes"
S9 THERMAL MODEL  THERMAL ELEMENTS  THERMAL MODEL TRIP: "Latched" or "Unlatched"
2.
Any trip must be reset prior to each test. Short the emergency restart terminals momentarily immediately prior to each
overload curve test to ensure that the thermal capacity used is zero. Failure to do so will result in shorter trip times.
Inject the current of the proper amplitude to obtain the values as shown and verify the trip times. Motor load may be
viewed in:
A2 METERING DATA  CURRENT METERING
3.
Thermal capacity used and estimated time to trip may be viewed in:
A1 STATUS  GENERATOR STATUS
AVERAGE PHASE
CURRENT DISPLAYED
PICKUP LEVEL
EXPECTED TIME TO
TRIP
TOLERANCE RANGE
1050 A
1.05 × FLA
never
n/a
1200 A
1.20 × FLA
795.44 sec.
779.53 to 811.35 sec.
1750 A
1.75 × FLA
169.66 sec.
166.27 to 173.05 sec.
3000 A
3.00 × FLA
43.73 sec.
42.86 to 44.60 sec.
6000 A
6.00 × FLA
9.99 sec.
9.79 to 10.19 sec.
10000 A
10.00 × FLA
5.55 sec.
5.44 to 5.66 sec.
NOTE
Generator Rated MVA
FLA = ----------------------------------------------------------------------------------------------------------3 × Generator Phase-to-Phase Voltage
GE Multilin
489 Generator Management Relay
MEASURED TIME TO
TRIP (SEC.)
7
(EQ 7.4)
7-9
7.3 ADDITIONAL FUNCTIONAL TESTS
7 TESTING
7.3.2 POWER MEASUREMENT TEST
The specification for reactive and apparent power is ± 1% of
steps below to verify accuracy.
1.
3 × 2 × CT × VT × VTfull-scale at Iavg < 2 × CT. Perform the
Alter the following setpoints:
S2 SYSTEM SETUP  CURRENT SENSING  PHASE CT PRIMARY: "1000"
S2 SYSTEM SETUP  VOLTAGE SENSING  VT CONNECTION TYPE: "Wye"
S2 SYSTEM SETUP  VOLTAGE SENSING  VOLTAGE TRANSFORMER RATIO: "10.00:1"
2.
Inject current and apply voltage as per the table below. Verify accuracy of the measured values. View the measured
values in:
A2 METERING DATA  POWER METERING
INJECTED CURRENT / APPLIED VOLTAGE
(IA IS THE REFERENCE VECTOR)
POWER QUANTITY
POWER FACTOR
1 A UNIT
5 A UNIT
EXPECTED
TOLERANCE
Ia = 1 A∠0°
Ib = 1 A∠120° lag
Ic = 1 A∠240° lag
Va = 120 V∠342° lag
Vb = 120 V∠102° lag
Vc = 120 V∠222° lag
Ia = 5 A∠0°
Ib = 5 A∠120° lag
Ic = 5 A∠240° lag
Ia = 120 V∠342° lag
Vb = 120 V∠102° lag
Vc = 120 V∠222° lag
MEASURED
EXPECTED
+3424 kW
3329 to 3519
kW
0.95 lag
Ia = 1 A∠0°
Ib = 1 A∠120° lag
Ic = 1 A∠240° lag
Va = 120 V∠288° lag
Vb = 120 V∠48° lag
Vc = 120 V∠168° lag
Ia = 5 A∠0°
Ib = 5 A∠120° lag
Ic = 5 A∠240° lag
Va = 120 V∠288° lag
Vb = 120 V∠48° lag
Vc = 120 V∠168° lag
+3424 kvar
3329 to 3519
kvar
0.31 lag
MEASURED
7
7-10
489 Generator Management Relay
GE Multilin
7 TESTING
7.3 ADDITIONAL FUNCTIONAL TESTS
7.3.3 REACTIVE POWER ACCURACY
The specification for reactive power is ±1% of
verify accuracy and trip element.
1.
3 × 2 × CT × VT × VTfull scale at Iavg < 2 × CT. Perform the steps below to
Alter the following system setpoints:
S2 SYSTEM SETUP  CURRENT SENSING  PHASE CT PRIMARY: "5000"
S2 SYSTEM SETUP  VOLTAGE SENSING  VT CONNECTION TYPE: "Wye"
S2 SYSTEM SETUP  VOLTAGE SENSING  VOLTAGE TRANSFORMER RATIO: "100:1"
S2 SYSTEM SETUP  GEN. PARAMETERS  GENERATOR RATED MVA: "100"
S2 SYSTEM SETUP  GEN. PARAMETERS  GENERATOR RATED POWER FACTOR: "0.85"
S2 SYSTEM SETUP  GEN. PARAMETERS  GENERATOR VOLTAGE PHASE-PHASE: "12000"
–1
The rated reactive power is 100 sin ( cos ( 0.85 ) ) = ± 52.7 Mvar .
2.
Alter the following reactive power setpoints:
S7 POWER ELEMENTS  REACTIVE POWER  REACTIVE POWER ALARM: "Unlatched"
S7 POWER ELEMENTS  REACTIVE POWER  ASSIGN ALARM RELAYS(2-5): "---5"
S7 POWER ELEMENTS  REACTIVE POWER  POSTIVE Mvar ALARM LEVEL: "0.6 x Rated"
S7 POWER ELEMENTS  REACTIVE POWER  NEGATIVE Mvar ALARM LEVEL: "0.6 x Rated"
S7 POWER ELEMENTS  REACTIVE POWER  REACTIVE POWER ALARM DELAY: "5 s"
S7 POWER ELEMENTS  REACTIVE POWER  REACTIVE POWER ALARM EVENT: "On"
S7 POWER ELEMENTS  REACTIVE POWER  REACTIVE POWER TRIP: "Unlatched"
S7 POWER ELEMENTS  REACTIVE POWER  ASSIGN TRIP RELAYS(1-4): "1---"
S7 POWER ELEMENTS  REACTIVE POWER  POSTIVE Mvar TRIP LEVEL: "0.75 x Rated"
S7 POWER ELEMENTS  REACTIVE POWER  NEGATIVE Mvar TRIP LEVEL: "0.75 x Rated"
S7 POWER ELEMENTS  REACTIVE POWER  REACTIVE POWER TRIP DELAY: "10 s"
3.
Inject current and apply voltage as per the table below. Verify the alarm/trip elements and the accuracy of the measured values. View the measured values in:
A2 METERING DATA  POWER METERING
4.
View the Event Records in A5 EVENT RECORD
CURRENT/
VOLTAGE
MVAR
ALARM
EXPECTED TOLERANCE MEASURED EXPECTED
OBSERVED
TRIP
DELAY
EXPECTED
N/A

N/A
N/A
Vab=120V∠0°
Vbc=120V∠120°lag
Vca=120V∠240°lag
Ian=5 A∠10°lag
Ibn=5 A∠130°lag
Icn=5 A∠250°lag
18
13 to 23

Vab=120V∠0°
Vbc=120V∠120°lag
Vca=120V∠240°lag
Ian=5 A∠340°lag
Ibn=5 A∠100°lag
Icn=5 A∠220°lag
–35
–40 to –30


Vab=120V∠0°
Vbc=120V∠120°lag
Vca=120V∠240°lag
Ian=5 A∠330°lag
Ibn=5 A∠90°lag
Icn=5 A∠210°lag
–52
–57 to –47


Vab=120V∠0°
Vbc=120V∠120°lag
Vca=120V∠240°lag
Ian=5 A∠30°lag
Ibn=5 A∠150°lag
Icn=5 A∠270°lag
52
47 to 57


OBSERVED
DELAY
: Activated, : Not Activated
GE Multilin
489 Generator Management Relay
7-11
7
7.3 ADDITIONAL FUNCTIONAL TESTS
7 TESTING
7.3.4 VOLTAGE PHASE REVERSAL ACCURACY
The can detect voltage phase rotation and protect against phase reversal. To test the phase reversal element, perform the
following steps:
1.
Alter the following setpoints:
S2 SYSTEM SETUP  VOLTAGE SENSING  VT CONNECTION TYPE: "Wye"
S2 SYSTEM SETUP  GEN. PARAMETERS  GENERATOR PHASE SEQUENCE: "ABC"
S3 DIGITAL INPUTS  BREAKER STATUS  BREAKER STATUS: "Breaker
Auxiliary a"
S6 VOLTAGE ELEMENTS  PHASE REVERSAL  PHASE REVERSAL TRIP: "Unlatched"
S6 VOLTAGE ELEMENTS  PHASE REVERSAL  ASSIGN TRIP RELAYS: "1---"
2.
Apply voltages as per the table below. Verify the operation on voltage phase reversal
APPLIED VOLTAGE
EXPECTED RESULT
Va = 120 V∠0°
Vb = 120 V∠120° lag
Vc = 120 V∠240° lag
NO TRIP
OBSERVED RESULT
Va = 120 V∠0°
Vb = 120 V∠240° lag
Vc = 120 V∠120° lag
PHASE REVERSAL TRIP
7.3.5 INJECTION TEST SETUP #2
Setup the 489 device as follows for the GE Multilin HGF Ground Accuracy Test, Neutral Voltage (3rd Harmonic) Accuracy
Test, and the Phase Differential Trip Test.
VC
3 PHASE VARIABLE AC TEST SET
VA
VB
IA
VA VB VC VN
NC
IB
IC
IN
NC
7
50:0.25
GROUND INPUTS
PHASE a PHASE b PHASE c
PHASE A PHASE B PHASE C
NEUTRAL END CT's
OUTPUT CT's
Vc
Vcom
Va
Vb
COM
COM
1A/5A
1A/5A
AUTOMATIC CT
SHORTING
BAR
COM
G6 H6 G7 H7 G8 H8 G2 H1 H2 G1
1A/5A
COM
1A/5A
COM
1A/5A
COM
COM
1A/5A
HGF
1A
COM
V
NEUTRAL
E10 F10 G9 H9 G10 H10 G3 H3 G4 H4 G5 H5
PHASE
VOLTAGE INPUTS
808817A1.CDR
Figure 7–2: SECONDARY INJECTION SETUP #2
7-12
489 Generator Management Relay
GE Multilin
7 TESTING
7.3 ADDITIONAL FUNCTIONAL TESTS
7.3.6 GE MULTILIN HGF GROUND ACCURACY
The specification for GE Multilin HGF 50:0.025 ground current input accuracy is ±0.5% of 2 × CT rated primary (25 A). Perform the steps below to verify accuracy.
1.
Alter the following setpoint:
S2 SYSTEM SETUP  CURRENT SENSING  GROUND CT: "50:0.025
2.
CT"
Measured values should be ±0.25 A. Inject the values shown in the table below either as primary values into a GE Multilin 50:0.025 Core Balance CT or as secondary values that simulate the core balance CT. Verify accuracy of the measured values in:
A2 METERING DATA  CURRENT METERING
INJECTED CURRENT
CURRENT READING
PRIMARY 50:0.025 CT
SECONDARY
EXPECTED
0.25 A
0.125 mA
0.25 A
1A
0.5 mA
1.00 A
5A
2.5 mA
5.00 A
10 A
5 mA
10.00 A
MEASURED
7.3.7 NEUTRAL VOLTAGE (3RD HARMONIC) ACCURACY
The 489 specification for neutral voltage (3rd harmonic) accuracy is ±0.5% of full scale (100 V). Perform the steps below to
verify accuracy.
1.
Alter the following setpoints:
S2 SYSTEM SETUP  VOLTAGE SENSING  NEUTRAL VOLTAGE TRANSFORMER: "Yes"
S2 SYSTEM SETUP  VOLTAGE SENSING  NEUTRAL V.T. RATIO: "10.00:1"
S2 SYSTEM SETUP  GEN. PARAMETERS  GENERATOR NOMINAL FREQUENCY: "60 Hz"
2.
Measured values should be ±5.0 V. Apply the voltage values shown in the table and verify accuracy of the measured
values. View the measured values in:
A2 METERING DATA  VOLTAGE METERING
APPLIED NEUTRAL
VOLTAGE AT 180 HZ
EXPECTED NEUTRAL
VOLTAGE
10 V
100 V
30 V
300 V
50 V
500 V
GE Multilin
MEASURED NEUTRAL
VOLTAGE
489 Generator Management Relay
7
7-13
7.3 ADDITIONAL FUNCTIONAL TESTS
7 TESTING
7.3.8 PHASE DIFFERENTIAL TRIP ACCURACY
NOTE
These tests will require a dual channel current source. The unit must be capable of injecting prefault currents and fault currents of a different value. Application of excessive currents (greater than 3 × CT) for
extended periods will cause damage to the relay.
a) MINIMUM PICKUP CHECK
1.
Connect the relay test set to inject Channel X current (Ix) into the G3 terminal and out of H3 terminal (Phase A).
Increase Ix until the differential element picks up. Record this value as pickup. Switch off the current. The theoretical
pickup can be computed as follows:
I XPU = Pickup setting × CT
(EQ 7.5)
b) SINGLE INFEED FAULT
2.
Set the Ix prefault current equal to 0. Set the fault current equal to CT. Apply the fault. Switch off the current. Record the
operating time.
3.
Set the Ix prefault current equal to 0. Set the fault current equal to 5 × CT. Apply the fault. Switch off the current. Record
the operating time.
c) SLOPE 1 CHECK
4.
Connect the relay test set to inject Channel Y current (IY) into the G6 terminal and out of H6 terminal. The angle
between Ix and IY will be 180°.
5.
Set pre-fault current, Ix and IY equal to zero.
6.
Set fault current, IY equal to 1½ CT.
7.
At this value the relay should operate according to the following formula:
2 – Slope 1 setting 3 × CT
I XOP1 = ------------------------------------------------- × ----------------2 + Slope 1 setting
2
8.
Set fault current, Ix equal to 0.95 × IXOP1. Apply the fault. The relay should operate. Switch off the current.
9.
Set fault current, Ix equal to 1.05 × IXOP1. Apply the fault. The relay should restrain. Switch off the current.
(EQ 7.6)
d) SLOPE 2 CHECK
7
10. Set fault current, IY equal to 2.5 × CT.
11. At this value the relay should operate according to the following formula.
2 – Slope 1 setting
I XOP2 = ------------------------------------------------- × 2.5 × CT
2 + Slope 1 setting
(EQ 7.7)
12. Set fault current, Ix equal to 0.95 × IXOP2. Switch on the test set. The relay should operate. Switch off the current.
13. Set fault current, Ix equal to 1.05 × IXOP2. Switch on the test set. The relay should restrain. Switch off the current.
e) DIRECTIONAL CHECK
14. Set pre-fault current, Ix and IY equal to 2.5 × CT. At this value the conditions for CT saturation detection are set and the
relay will enable the directional check.
15. Set fault current, Ix equal to 0.95 × IXOP2. Switch on the test set. The relay should restrain. Switch off the current.
16. Repeat Steps 1 through 15 for phases B and C.
7-14
489 Generator Management Relay
GE Multilin
7 TESTING
7.3 ADDITIONAL FUNCTIONAL TESTS
f) TEST RESULTS
TEST
PHASE A
CALCULATED
PHASE B
MEASURED
CALCULATED
PHASE C
MEASURED
CALCULATED
MEASURED
Minimum Pickup
TEST
PHASE A
PHASE B
5 × CT
CT
RESTRAIN
OPERATE
CT
PHASE C
5 × CT
CT
5 × CT
RESTRAIN
OPERATE
Single Infeed Fault
TEST
PHASE A
OPERATE
Slope 1
PHASE B
PHASE C
RESTRAIN
Ix
Iy
Operation
(OK/not OK)
Slope 2
Ix
Iy
Operation
(OK/not OK)
Directional
Check
Ix
N/A
N/A
N/A
Iy
N/A
N/A
N/A
Operation
(OK/not OK)
N/A
N/A
N/A
7.3.9 INJECTION TEST SETUP #3
Setup the 489 device as follows for the Voltage Restrained Overcurrent test.
VC
3 PHASE VARIABLE AC TEST SET
VA
VB
IA
VA VB VC VN
IB
IC
IN
7
PHASE a PHASE b PHASE c
PHASE A PHASE B PHASE C
NEUTRAL END CT's
OUTPUT CT's
Vc
Vcom
Va
Vb
COM
COM
1A/5A
COM
AUTOMATIC CT
SHORTING
BAR
1A/5A
G6 H6 G7 H7 G8 H8 G2 H1 H2 G1
1A/5A
COM
COM
1A/5A
COM
1A/5A
1A/5A
HGF
GROUND INPUTS
COM
1A
COM
V
NEUTRAL
E10 F10 G9 H9 G10 H10 G3 H3 G4 H4 G5 H5
PHASE
VOLTAGE INPUTS
808822A2.CDR
Figure 7–3: SECONDARY INJECTION TEST SETUP #3
GE Multilin
489 Generator Management Relay
7-15
7.3 ADDITIONAL FUNCTIONAL TESTS
7 TESTING
7.3.10 VOLTAGE RESTRAINED OVERCURRENT ACCURACY
Setup the relay as shown in Figure 7–3: Secondary Injection Test Setup #3 on page 7–15.
1.
Alter the following setpoints.
S2 SYSTEM SETUP  GEN. PARAMETERS  GENERATOR RATED MVA: "100 MVA"
S2 SYSTEM SETUP  GEN. PARAMETERS  GENERATOR VOLTAGE PHASE-PHASE: "12000"
S2 SYSTEM SETUP  VOLTAGE SENSING  VT CONNECTION TYPE: "Open Delta"
S2 SYSTEM SETUP  VOLTAGE SENSING  VOLTAGE TRANSFORMER RATIO: "100:1"
S5 CURRENT ELEMENTS  OVERCURRENT ALARM  OVERCURRENT ALARM: "Unlatched"
S5 CURRENT ELEMENTS  OVERCURRENT ALARM  O/C ALARM LEVEL: "1.10 x FLA"
S5 CURRENT ELEMENTS  OVERCURRENT ALARM  OVERCURRENT ALARM DELAY: "2 s"
S5 CURRENT ELEMENTS  OVERCURRENT ALARM  O/C ALARM EVENTS: "On"
S5 CURRENT ELEMENTS  PHASE OVERCURRENT  PHASE OVERCURRENT TRIP: "Latched"
S5 CURRENT ELEMENTS  PHASE OVERCURRENT  ENABLE VOLTAGE RESTRAINT: "Yes"
S5 CURRENT ELEMENTS  PHASE OVERCURRENT  PHASE O/C PICKUP: "1.5 x CT"
S5 CURRENT ELEMENTS  PHASE OVERCURRENT  CURVE SHAPE: "ANSI Extremely Inv."
S5 CURRENT ELEMENTS  PHASE OVERCURRENT  O/C CURVE MULTIPLIER: "2.00"
S5 CURRENT ELEMENTS  PHASE OVERCURRENT  O/C CURVE RESET: "Instantaneous"
2.
The trip time for the extremely inverse ANSI curve is given as:


B
E
D
 A + -----------------------------+ --------------------------------------2- + --------------------------------------3-
I Time to Trip = M × 
I I 
 ------------------------------------– C  ------------------– C
– C 

  K × I p

  K × I p

 K × I p


where:
3.
(EQ 7.8)
M = O/C CURVE MULTIPLIER setpoint, I = input current, Ip = PHASE O/C PICKUP setpoint
A, B, C, D, E = curve constants; A = 0.0399, B = 0.2294, C = 0.5000, D = 3.0094, E = 0.7222
K = voltage restrained multiplier <optional>
The voltage restrained multiplier is calculated as:
phase-to-phase voltage
K = -----------------------------------------------------------------------------rated phase-to-phase voltage
(EQ 7.9)
and has a range of 0.1 to 0.9.
4.
7
Using Figure 7–3: Secondary Injection Test Setup #3 on page 7–15, inject current and apply voltage as per the table
below. Verify the alarm/trip elements and view the event records in A5 EVENT RECORD.
CURRENT/VOLTAGE (5 A UNIT)
ALARM
CURRENT
VOLTAGE
Ian = 5 A∠0°
Ibn = 5 A∠120° lag
Icn = 5 A∠240° lag
Vab = 120 V∠0° lag
Vbc = 120 V∠120° lag
Vca = 120 V∠240° lag

Ian = 6 A∠0°
Ibn = 6 A∠120° lag
Icn = 6 A∠240° lag
Vab = 120 V∠0°
Vbc = 120 V∠120° lag
Vca = 120 V∠240° lag
Ian = 10 A∠0°
Ibn = 10 A∠120° lag
Icn = 10 A∠240° lag
EXPECTED OBSERVED
TRIP
DELAY
TRIP DELAY
EXPECTED OBSERVED EXPECTED OBSERVED
N/A

N/A
N/A


N/A
N/A
Vab = 120 V∠0°
Vbc = 120 V∠120° lag
Vca = 120 V∠240° lag


11.8 sec.
Ian = 10 A∠0°
Ibn = 10 A∠120° lag
Icn = 10 A∠240° lag
Vab = 100 V∠0°
Vbc = 100 V∠120° lag
Vca = 100 V∠240° lag


6.6 sec.
Ian = 10 A∠0°
Ibn = 10 A∠120° lag
Icn = 10 A∠240° lag
Vab = 60 V∠0°
Vbc = 60 V∠120° lag
Vca = 60 V∠240° lag


1.7 sec.
 activated;  Not Activated
7-16
489 Generator Management Relay
GE Multilin
APPENDIX A
A.1 STATOR GROUND FAULT
APPENDIX A Application NotesA.1 Stator Ground Fault
CAUTION
A.1.1 DESCRIPTION
This application note describes general protection concepts and provides guidelines on the use of the 489
to protect a generator stator against ground faults. Detailed connections for specific features must be
obtained from the relay manual. Users are also urged to review the material contained in the 489 manual on
each specific protection feature discussed here.
The 489 Generator Management Relay offers a number of elements to protect a generator against stator ground faults.
Inputs are provided for a neutral-point voltage signal and for a zero-sequence current signal. The zero-sequence current
input can be into a nominal 1 A secondary circuit or an input reserved for a special GE Multilin type HGF ground CT for very
sensitive ground current detection. Using the HGF CT allows measurement of ground current values as low as 0.25 A primary. With impedance-grounded generators, a single ground fault on the stator does not require that the unit be quickly
removed from service. The grounding impedance limits the fault current to a few amperes. A second ground fault can, however, result in significant damage to the unit. Thus the importance of detecting all ground faults, even those in the bottom
5% of the stator. The fault detection methods depend on the grounding arrangement, the availability of core balance CT,
and the size of the unit. With modern full-featured digital generator protection relays such as the 489, users do not incur
additional costs for extra protection elements as they are all part of the same device. This application note provides general
descriptions of each of the elements in the 489 suitable for stator ground protection, and discusses some special applications.
A.1.2 NEUTRAL OVERVOLTAGE ELEMENT
The simplest, and one of the oldest methods to detect stator ground faults on high-impedance-grounded generators, is to
sense the voltage across the stator grounding resistor (See References [1, 2] at the end of this section). This is illustrated,
in a simplified form in the figure below. The voltage signal is connected to the Vneutral input of the 489, terminals E10 and
F10. The Vneutral signal is the input signal for the 489 neutral overvoltage protection element. This element has an alarm
and a trip function, with separately adjustable operate levels and time delays. The trip function offers a choice of timing
curves as well as a definite time delay. The neutral overvoltage function responds to fundamental frequency voltage at the
generator neutral. It provides ground fault protection for approximately 95% of the stator winding. The limiting factor is the
level of voltage signal available for a fault in the bottom 5% of the stator winding. The element has a range of adjustment,
for the operate levels, of 2 to 100 V.
Generator
R is selected for a
maximum fault current
of 10 A, typically.
Distribution
Transformer
R
Overvoltage
Relay
808739A1.CDR
Figure A–1: STATOR GROUND FAULT PROTECTION
The operating time of this element should be coordinated with protective elements downstream, such as feeder ground
fault elements, since the neutral overvoltage element will respond to external ground faults if the generator is directly connected to a power grid, without the use of a delta-wye transformer.
In addition, the time delay should be coordinated with the ground directional element (discussed later), if it is enabled, by
using a longer delay on the neutral overvoltage element than on the directional element.
It is recommended that an isolation transformer be used between the relay and the grounding impedance to reduce common mode voltage problems, particularly on installations requiring long leads between the relay and the grounding impedance.
GE Multilin
489 Generator Management Relay
A-1
A
A.1 STATOR GROUND FAULT
A
APPENDIX A
When several small generators are operated in parallel with a single step-up transformer, all generators may be grounded
through the same impedance (the impedance normally consists of a distribution transformer and a properly sized resistor).
It is possible that only one generator is grounded while the others have a floating neutral point when connected to the
power grid (see the figure below). This operating mode is often adopted to prevent circulation of third-harmonic currents
through the generators, if the installation is such that all the star points would end up connected together ahead of the common grounding impedance (if each generator has its own grounding impedance, the magnitude of the circulating third harmonic current will be quite small). With a common ground point, the same Vneutral signal is brought to all the relays but only
the one which is grounded should have the neutral overvoltage element in service.
For these cases, the neutral overvoltage element has been provided with a supervising signal obtained from an auxiliary
contact off the grounding switch. When the grounding switch is opened, the element is disabled. The grounding switch auxiliary contact is also used in the ground directional element, as is the breaker auxiliary contact, as discussed later.
If all the generators are left grounded through the same impedance, the neutral overvoltage element in each relay will
respond to a ground fault in any of the generators. For this reason, the ground directional element should be used in each
relay, in addition to the neutral overvoltage element.
Common
Grounding
Impedance
Grounding
Switch
G1
Breaker
Trans. & R
Isolating
Trans.
Aux.
Contact
Aux.
Contact
489
Relay
Vneutral
Grounding
Switch
G2
Breaker
Aux.
Contact
Vneutral
Aux.
Contact
489
Relay
Other Generators,
as the case may be
808737A1.CDR
Figure A–2: PARALLEL GENERATORS WITH COMMON GROUNDING IMPEDANCE
A.1.3 GROUND OVERCURRENT ELEMENT
The ground overcurrent element can be used as a direct replacement or a backup for the neutral overvoltage element, with
the appropriate current signal from the generator neutral point, for grounded generators. This element can also be used
with a Core Balance CT, either in the neutral end or the output end of the generator, as shown below. The use of the special
CT, with its dedicated input to the relay, offers very sensitive current detection, but still does not offer protection for the full
stator. The setting of this element must be above the maximum unbalance current that normally flows in the neutral circuit.
Having the element respond only to the fundamental frequency component allows an increase in sensitivity.
The core balance CT can be a conventional CT or a 50:0.025 Ground CT, allowing the measurement of primary-side current levels down to 0.25 A. Using a Core Balance CT, on the output side of the transformer will provide protection against
stator ground faults in ungrounded generators, provided that there is a source of zero-sequence current from the grid.
Though in theory one could use this element with a zero sequence current signal obtained from a summation of the three
phase currents (neutral end or output end), by connecting it in the star point of the phase CTs, Options 4 and 5 in the figure
below, this approach is not very useful. The main drawback, for impedance-grounded generators is that the zero-sequence
current produced by the CT ratio and phase errors could be much larger than the zero sequence current produced by a real
ground fault inside the generator.
A-2
489 Generator Management Relay
GE Multilin
APPENDIX A
A.1 STATOR GROUND FAULT
Again the time delay on this element must be coordinated with protection elements downstream, if the generator is
grounded. Refer to Section 4.6.7: Ground Overcurrent on page 4–29 for the range of settings of the pickup levels and the
time delays. The time delay on this element should always be longer than the longest delay on line protection downstream.
GENERATOR
CORE
BALANCE
CT
Option 2
Option 1
CORE
BALANCE
CT
Option 5
(similar to
Option 4)
Phase CTs
BREAKER
Breaker
Aux.
Option 3
489
Option 4
Ground
Overcurrent
Element
Ground current input
from one of the five
options
808736A1.CDR
Figure A–3: GROUND OVERCURRENT ELEMENT WITH DIFFERENT CURRENT SOURCE SIGNALS
A.1.4 GROUND DIRECTIONAL ELEMENT
The 489 can detect internal stator ground faults using a Ground Directional element implemented using the Vneutral and the
ground current inputs. The voltage signal is obtained across the grounding impedance of the generator. The ground, or
zero sequence, current is obtained from a core balance CT, as shown below (due to CT inaccuracies, it is generally not
possible to sum the outputs of the conventional phase CTs to derive the generator high-side zero sequence current, for an
impedance-grounded generator).
If correct polarities are observed in the connection of all signals to the relay, the Vneutral signal will be in phase with the
ground current signal. The element has been provided with a setting allowing the user to change the plane of operation to
cater to reactive grounding impedances or to polarity inversions.
This element’s normal "plane of operation" for a resistor-grounded generator is the 180° plane, as shown in Figure A–4:
Ground Directional Element Polarities and Plane of Operation, for an internal ground fault. That is, for an internal stator-toground fault, the Vo signal is 180° away from the Io signal, if the polarity convention is observed. If the grounding impedance is inductive, the plane of operation will be the 270° plane, again, with the polarity convention shown below. If the polarity convention is reversed on one input, the user will need to change the plane of operation by 180°.
GENERATOR
Io
Io
CORE
BALANCE
CT
90°
Plane of operation
for resistive
grounding impedance
Io
180°
0°
Vo
±
Grounding
Resistor
F10
E10
489
Relay
H10
Io
G10
±
Isolating
Transformer
270°
808735A1.CDR
Figure A–4: GROUND DIRECTIONAL ELEMENT POLARITIES AND PLANE OF OPERATION
GE Multilin
489 Generator Management Relay
A-3
A
A.1 STATOR GROUND FAULT
APPENDIX A
A
GENERATOR
CORE
BALANCE
CT
BREAKER
Aux.
Contact
Grounding
Switch
Aux.
Breaker
489
To Relay
Grounding
Impedance
(Trans. &
Resistor)
Ground
Directional
Element
(or O/C)
Vneutral
Input
Isolating
Transformer
Grounding
Switch
Aux. Cont.
Neutral
O/V
Element
Ground
Current
Input
Ground
O/C
Element
G.S.
Status
Breaker
Status
808734A1.CDR
Figure A–5: GROUND DIRECTIONAL ELEMENT CONCEPTUAL ARRANGEMENT
The operating principle of this element is quite simple: for internal ground faults the two signals will be 180° out of phase
and for external ground faults, the two signals will be in phase. This simple principle allows the element to be set with a high
sensitivity, not normally possible with an overcurrent element.
The current pickup level of the element can be adjusted down to 0.05 × CT primary, allowing an operate level of 0.25 A primary if the 50:0.025 ground CT is used for the core balance. The minimum level of Vneutral at which the element will operate
is determined by hardware limitations and is internally set at 2.0 V.
Because this element is directional, it does not need to be coordinated with downstream protections and a short operating
time can be used. Definite time delays are suitable for this element.
Applications with generators operated in parallel and grounded through a common impedance require special considerations. If only one generator is grounded and the other ones left floating, the directional element for the floating generators
does not receive a correct Vneutral signal and therefore cannot operate correctly. In those applications, the element makes
use of auxiliary contacts off the grounding switch and the unit breaker to turn the element into a simple overcurrent element,
with the pickup level set for the directional element (note that the ground directional element and the ground overcurrent
elements are totally separate elements). In this mode, the element can retain a high sensitivity and fast operate time since
it will only respond to internal stator ground faults. The table below illustrates the status of different elements under various
operating conditions.
Table A–1: DETECTION ELEMENT STATUS
GENERATOR
CONDITION
UNIT
BREAKER
GROUNDING
SWITCH
Shutdown
Open
Open
Open Circuit and
grounded
Open
Closed
Loaded and
Grounded
Closed
Closed
Loaded and Not
Grounded
Closed
Open
A-4
ELEMENT
GROUND
DIRECTIONAL
NEUTRAL
OVERVOLTAGE
GROUND
OVERCURRENT
Out-of-service
Out-of-service
In-service
In-service (but will not
operate due to lack of LO)
In-service
In-service
In-service
In-service
In-service
In service as a simple
overcurrent element
Out-of-service
In-service
489 Generator Management Relay
GE Multilin
APPENDIX A
A.1 STATOR GROUND FAULT
A.1.5 THIRD HARMONIC VOLTAGE ELEMENT
The conventional neutral overvoltage element or the ground overcurrent element are not capable of reliably detecting stator
ground faults in the bottom 5% of the stator, due to lack of sensitivity. In order to provide reliable coverage for the bottom
part of the stator, protective elements, utilizing the third harmonic voltage signals in the neutral and at the generator output
terminals, have been developed (see Reference 4).
In the 489 relay, the third-harmonic voltage element, Neutral Undervoltage (3rd Harmonic) derives the third harmonic component of the neutral-point voltage signal from the Vneutral signal as one signal, called VN3. The third harmonic component
of the internally summed phase-voltage signals is derived as the second signal, called VP3. For this element to perform as
originally intended, it is necessary to use wye-connected VTs.
Since the amount of third harmonic voltage that appears in the neutral is both load and machine dependent, the protection
method of choice is an adaptive method. The following formula is used to create an adaptive third-harmonic scheme:
V N3
--------------------------------- ≤ 0.15
V P3 ⁄ 3 + V N3
which simplifies to
V P3 ≥ 17V N3
(EQ A.1)
The 489 tests the following conditions prior to testing the basic operating equation to ensure that VN3 is of a measurable
magnitude:
V P3′ > 0.25 V
where:
and
Neutral CT Ratio
V P3′ ≥ Permissive_Threshold × 17 × -------------------------------------------Phase CT Ratio
(EQ A.2)
VN3 is the magnitude of third harmonic voltage at the generator neutral
VP3 is the magnitude of third harmonic voltage at the generator terminals
VP3' and VN3' are the corresponding voltage transformer secondary values
Permissive_Threshold is 0.15 V for the alarm element and 0.1875 V for the trip element.
In addition, the logic for this element verifies that the generator positive sequence terminal voltage is at least 30% of nominal, to ensure that the generator is actually excited.
This method of using 3rd harmonic voltages to detect stator ground faults near the generator neutral has proved
feasible on larger generators with unit transformers. Its usefulness in other generator applications is unknown.
NOTE
If the phase VT connection is "open delta", it is not possible to measure the third harmonic voltage at the generator terminals and a simple third harmonic neutral undervoltage element is used. In this case, the element is supervised by both a
terminal voltage level and by a power level. When used as a simple undervoltage element, settings should be based on
measured 3rd harmonic neutral voltage of the healthy machine. It is recommended that the element only be used for alarm
purposes with open delta VT connections.
A.1.6 REFERENCES
1.
C. R. Mason, "The Art & Science of Protective Relaying", John Wiley & Sons, Inc., 1956, Chapter 10.
2.
J. Lewis Blackburn, "Protective Relaying: Principles and Applications", Marcel Dekker, Inc., New York, 1987, chapter 8.
3.
GE Multilin, "Instruction Manual for the 489 Generator Management Relay".
4.
R. J. Marttila, "Design Principles of a New Generator Stator Ground Relay for 100% Coverage of the Stator Winding",
IEEE Transactions on Power Delivery, Vol. PWRD-1, No. 4, October 1986.
GE Multilin
489 Generator Management Relay
A-5
A
A.2 CURRENT TRANSFORMERS
A
A.2 Current Transformers
APPENDIX A
A.2.1 GROUND FAULT CTS FOR 50:0.025 A CT
CTs that are specially designed to match the ground fault input of GE Multilin motor protection relays should be used to
ensure correct performance. These CTs have a 50:0.025A (2000:1 ratio) and can sense low leakage currents over the relay
setting range with minimum error. Three sizes are available with 3½", 5½", or 8" diameter windows.
HGF3 / HGF5
DIMENSIONS
HGF8
DIMENSIONS
808710A1.CDR
A-6
489 Generator Management Relay
GE Multilin
APPENDIX A
A.2 CURRENT TRANSFORMERS
A.2.2 GROUND FAULT CTS FOR 5 A SECONDARY CT
For low resistance or solidly grounded systems, a 5 A secondary CT should be used. Two sizes are available with 5½” or
13” × 16” windows. Various Primary amp CTs can be chosen (50 to 250).
GCT5
GCT16
DIMENSIONS
DIMENSIONS
808709A1.CDR
GE Multilin
489 Generator Management Relay
A-7
A
A.2 CURRENT TRANSFORMERS
A
APPENDIX A
A.2.3 PHASE CTS
Current transformers in most common ratios from 50:5 to 1000:5 are available for use as phase current inputs with motor
protection relays. These come with mounting hardware and are also available with 1 A secondaries. Voltage class: 600 V
BIL, 10 KV.
808712A1.CDR
A-8
489 Generator Management Relay
GE Multilin
APPENDIX B
B.1 TIME OVERCURRENT CURVES
APPENDIX B CurvesB.1 Time Overcurrent Curves
GE Multilin
B.1.1 ANSI CURVES
489 ANSI
MODERATELY INVERSE
1000
B
100
MULTIPLIER
10
TRIP TIME (sec)
30.0
20.0
15.0
10.0
8.0
6.0
1
4.0
3.0
2.0
1.0
0.5
0.1
0.01
0.1
1
10
CURRENT (I/Ipu)
100
808802A4.CDR
Figure B–1: ANSI MODERATELY INVERSE CURVES
GE Multilin
489 Generator Management Relay
B-1
B.1 TIME OVERCURRENT CURVES
APPENDIX B
GE Multilin
489 ANSI
NORMALLY INVERSE
1000
B
100
MULTIPLIER
TRIP TIME (sec)
10
30.0
20.0
15.0
10.0
8.0
1
6.0
4.0
3.0
2.0
1.0
0.1
0.5
0.01
0.1
1
10
CURRENT (I/Ipu)
100
808801A4.CDR
Figure B–2: ANSI NORMALLY INVERSE CURVES
B-2
489 Generator Management Relay
GE Multilin
APPENDIX B
B.1 TIME OVERCURRENT CURVES
489 ANSI
VERY INVERSE
GE Multilin
1000
B
100
10
TRIP TIME (sec)
MULTIPLIER
30.0
20.0
15.0
1
10.0
8.0
6.0
4.0
3.0
2.0
1.0
0.1
0.5
0.01
0.1
1
10
CURRENT (I/Ipu)
100
808800A4.DWG
Figure B–3: ANSI VERY INVERSE CURVES
GE Multilin
489 Generator Management Relay
B-3
B.1 TIME OVERCURRENT CURVES
APPENDIX B
489 ANSI
EXTREME INVERSE
GE Multilin
1000
B
100
TRIP TIME (sec)
10
MULTIPLIER
30.0
20.0
1
15.0
10.0
8.0
6.0
4.0
3.0
2.0
0.1
1.0
0.5
0.01
0.1
1
10
CURRENT (I/Ipu)
100
808799A4.CDR
Figure B–4: ANSI EXTREMELY INVERSE CURVES
B-4
489 Generator Management Relay
GE Multilin
APPENDIX B
B.1 TIME OVERCURRENT CURVES
B.1.2 DEFINITE TIME CURVES
489
DEFINITE TIME
GE Multilin
1000
B
100
TRIP TIME (sec)
10
MULTIPLIER
30.0
20.0
15.0
10.0
1
8.0
6.0
4.0
3.0
2.0
1.0
0.1
0.5
100
10
1
0.1
0.01
CURRENT (I/Ipu)
808798A4.CDR
Figure B–5: DEFINITE TIME CURVES
GE Multilin
489 Generator Management Relay
B-5
B.1 TIME OVERCURRENT CURVES
APPENDIX B
B.1.3 IAC CURVES
GE Multilin
489 IAC
SHORT INVERSE
1000
B
100
MULTIPLIER
TRIP TIME (sec)
10
30.0
1
20.0
15.0
10.0
8.0
6.0
4.0
3.0
0.1
2.0
1.0
0.5
CURRENT (I/Ipu)
100
10
1
0.1
0.01
808811A4.CDR
Figure B–6: IAC SHORT INVERSE CURVES
B-6
489 Generator Management Relay
GE Multilin
APPENDIX B
B.1 TIME OVERCURRENT CURVES
489
IAC INVERSE
GE Multilin
1000
B
100
MULTIPLIER
10
TRIP TIME (sec)
30.0
20.0
15.0
10.0
8.0
6.0
4.0
1
3.0
2.0
1.0
0.5
0.1
CURRENT (I/Ipu)
100
10
1
0.1
0.01
808810A4.CDR
Figure B–7: IAC INVERSE CURVES
GE Multilin
489 Generator Management Relay
B-7
B.1 TIME OVERCURRENT CURVES
APPENDIX B
489 IAC
VERY INVERSE
GE Multilin
1000
B
100
10
TRIP TIME (sec)
MULTIPLIER
30.0
20.0
15.0
10.0
8.0
1
6.0
4.0
3.0
2.0
1.0
0.1
0.5
CURRENT (I/Ipu)
100
10
1
0.1
0.01
808807A3.CDR
Figure B–8: IAC VERY INVERSE CURVES
B-8
489 Generator Management Relay
GE Multilin
APPENDIX B
B.1 TIME OVERCURRENT CURVES
489 IAC
EXTREME INVERSE
GE Multilin
1000
B
100
TRIP TIME (sec)
10
MULTIPLIER
30.0
1
20.0
15.0
10.0
8.0
6.0
4.0
3.0
0.1
2.0
1.0
0.5
CURRENT (I/Ipu)
100
10
1
0.1
0.01
808806A4.CDR
Figure B–9: IAC EXTREME INVERSE CURVES
GE Multilin
489 Generator Management Relay
B-9
B.1 TIME OVERCURRENT CURVES
APPENDIX B
B.1.4 IEC CURVES
GE Multilin
489
IEC CURVE A (BS142)
1000
B
100
TRIP TIME (sec)
10
MULTIPLIER
1.00
0.80
0.60
0.50
0.40
1
0.30
0.20
0.15
0.10
0.05
0.1
CURRENT (I/Ipu)
100
10
1
0.1
0.01
808803A4.CDR
Figure B–10: IEC CURVES A (BS142)
B-10
489 Generator Management Relay
GE Multilin
APPENDIX B
B.1 TIME OVERCURRENT CURVES
GE Multilin
489
IEC CURVE B (BS142)
1000
B
100
TRIP TIME (sec)
10
MULTIPLIER
1
1.00
0.80
0.60
0.50
0.40
0.30
0.20
0.15
0.1
0.10
0.05
100
10
1
0.1
0.01
CURRENT (I/Ipu)
808804A4.CDR
Figure B–11: IEC CURVES B (BS142)
GE Multilin
489 Generator Management Relay
B-11
B.1 TIME OVERCURRENT CURVES
APPENDIX B
GE Multilin
489
IEC CURVE C (BS142)
1000
B
100
TRIP TIME (sec)
10
1
MULTIPLIER
1.00
0.80
0.60
0.50
0.1
0.40
0.30
0.20
0.15
0.10
0.05
CURRENT (I/Ipu)
100
10
1
0.1
0.01
808805A4.CDR
Figure B–12: IEC CURVES C (BS142)
B-12
489 Generator Management Relay
GE Multilin
APPENDIX C
C.1 REVISION HISTORY
APPENDIX C MiscellaneousC.1 Revision History
C.1.1 CHANGE NOTES
Table C–1: REVISION HISTORY
MANUAL P/N
REVISION
RELEASE DATE
ECO
1601-0071-E1
---
---
N/A
1601-0071-E2
32E120A8.000
20 February 1997
489-018
1601-0071-E3
32F131A8.000
22 December 1997
489-039
1601-0071-E4
32F131A8.000
21 December 1998
489-087
1601-0071-E5
32F132A8.000
10 March 1999
489-107
1601-0071-E6
32F132A8.000
10 June 1999
489-110
1601-0071-E7
32G140A8.000
2 March 2000
489-141
1601-0071-E8
32H150A8.000
11 December 2001
489-209
1601-0071-E9
32I151A8.000
21 August 2002
489-222
1601-0071-EA
32I151A8.000
26 July 2006
489-260
1601-0071-EB
32I151A8.000
12 June 2008
08-0364
1601-0071-EC
32I151A8.000
15 July 2013
13-0514
C
C.1.2 CHANGES SINCE LAST REVISION
Table C–2: UPDATES FOR 489 MANUAL REVISION EC
PAGE
(EB)
PAGE
(EC)
CHANGE
DESCRIPTION
Title
Title
Update
Manual part number from EB to EC
Title
Title
Update
Updated title page format and content
1-3
1-3
Update
Updated 489 Order Codes Table
GE Multilin
489 Generator Management Relay
C-1
C.2 EU DECLARATION OF CONFORMITY
C.2 EU Declaration of Conformity
APPENDIX C
C.2.1 EU DECLARATION OF CONFORMITY
C
C-2
489 Generator Management Relay
GE Multilin
APPENDIX C
C.3 WARRANTY INFORMATION
C.3 Warranty Information
C.3.1 GE MULTILIN WARRANTY
GE Multilin Relay Warranty
C
General Electric Multilin Inc. (GE Multilin) warrants each
relay it manufactures to be free from defects in material and
workmanship under normal use and service for a period of
24 months from date of shipment from factory.
In the event of a failure covered by warranty, GE Multilin will
undertake to repair or replace the relay providing the warrantor determined that it is defective and it is returned with
all transportation charges prepaid to an authorized service
centre or the factory. Repairs or replacement under warranty
will be made without charge.
Warranty shall not apply to any relay which has been subject
to misuse, negligence, accident, incorrect installation or use
not in accordance with instructions nor any unit that has
been altered outside a GE Multilin authorized factory outlet.
GE Multilin is not liable for special, indirect or consequential
damages or for loss of profit or for expenses sustained as a
result of a relay malfunction, incorrect application or adjustment.
For complete text of Warranty (including limitations and disclaimers), refer to GE Multilin Standard Conditions of Sale.
GE Multilin
489 Generator Management Relay
C-3
C.3 WARRANTY INFORMATION
APPENDIX C
C
C-4
489 Generator Management Relay
GE Multilin
INDEX
Numerics
0-1mA ANALOG INPUT .................................................... 2-12
4-20mA ANALOG INPUT .................................................. 2-12
489PC
see SOFTWARE
50:0.025 CT ..................................................................... 2-10
A
ACCESS SWITCH ............................................................ 4-14
ACCESSORIES ................................................................. 1-3
ACTUAL VALUES
messages ......................................................................... 5-2
printing .......................................................................... 3-11
software ......................................................................... 3-11
ALARM PICKUPS .............................................................. 5-9
ALARM RELAY ........................................................2-13, 4-20
ALARM STATUS ................................................................ 5-4
ALARMS ............................................................................ 4-5
ANALOG IN MIN/MAX ...................................................... 5-19
ANALOG INPUTS ............................................................ 2-11
actual values ..........................................................5-17, 5-19
analog I/P min/max .......................................................... 4-11
DNP point list ................................................................. 6-47
min/max ......................................................................... 5-19
minimums and maximums ................................................. 4-16
setpoints ........................................................................ 4-76
specifications .................................................................... 1-4
testing ............................................................................. 7-7
ANALOG OUTPUTS ......................................................... 2-12
setpoints ........................................................................ 4-75
specifications .................................................................... 1-5
table .............................................................................. 4-76
testing ............................................................................. 7-7
ANSI CURVES .......................................................... 4-21, B-1
ANSI DEVICE NUMBERS ................................................... 1-1
APPLICATION NOTES
current transformers .......................................................... A-6
stator ground fault ............................................................. A-1
AUXILIARY RELAY ..................................................2-13, 4-20
B
BAUD RATE ........................................................ 1-5, 4-8, 6-1
BINARY COUNTER DNP POINTS .................................... 6-46
BINARY INPUTS DNP POINTS ......................................... 6-43
BINARY OUTPUTS DNP POINTS ..................................... 6-45
BREAKER FAILURE ........................................................ 4-69
BREAKER STATUS ......................................................... 4-14
BURDEN ........................................................................... 1-4
C
CALIBRATION INFO ........................................................ 5-25
CASE ......................................................................... 1-8, 2-1
CAUSE OF EVENTS TABLE ............................................. 5-24
CERTIFICATIONS .............................................................. 1-8
CHANGES TO MANUAL .....................................................C-1
CLEAR DATA .................................................................. 4-11
CLOCK ..................................................................... 4-9, 5-12
COMM PORT MONITOR .................................................. 4-82
COMMUNICATIONS
configuration .................................................................... 3-7
data frame format .............................................................. 6-1
data rate .......................................................................... 6-1
GE Multilin
error responses ................................................................. 6-7
monitoring ...................................................................... 4-82
passcode .......................................................................... 6-9
setpoints .......................................................................... 4-8
specifications .................................................................... 1-4
CONTROL FEATURES ....................................................... 4-5
CONTROL POWER ............................................................ 2-9
COOLING ........................................................................ 4-66
COOLING TIME CONSTANTS .......................................... 4-66
CORE BALANCE .............................................................. 2-10
CRC-16 ..............................................................................6-2
CT RATIO ........................................................................ 4-12
CTs
burden ............................................................................. 1-4
ground fault ..................................................................... A-7
phase .............................................................................. A-8
setpoints ........................................................................ 4-12
withstand .......................................................................... 1-4
CURRENT ACCURACY TEST ............................................. 7-3
CURRENT DEMAND ........................................................ 4-72
CURRENT INPUTS ............................................................ 1-4
CURRENT METERING ..................................................... 5-13
CURRENT SENSING ........................................................ 4-12
CURVES
see OVERLOAD CURVES
CUSTOM OVERLOAD CURVE .......................................... 4-60
CYCLIC REDUNDANCY CHECK
see CRC-16
D
DATA FRAME FORMAT ...................................................... 6-1
DATA PACKET FORMAT .................................................... 6-1
DATA RATE ....................................................................... 6-1
DEFAULT MESSAGES ....................................... 4-8, 4-9, 4-10
DEFAULT VARIATIONS .................................................... 6-42
DEFINITE TIME CURVE ............................................4-23, B-5
DEMAND DATA ................................................................ 4-16
DEMAND METERING ....................................... 1-5, 4-72, 5-17
DEMAND PERIOD ............................................................ 4-73
DESCRIPTION ................................................................... 1-1
DEVICE NUMBERS ............................................................ 1-1
DIAGNOSTIC MESSAGES ................................................ 5-26
DIELECTRIC STRENGTH
specifications .................................................................... 1-8
testing ............................................................................ 2-15
DIFFERENTIAL CURRENT ACCURACY TEST .................... 7-4
DIGITAL COUNTER ......................................................... 4-16
DIGITAL INPUTS ............................................................. 2-11
actual values ................................................................... 5-12
dual setpoints .................................................................. 4-16
field-breaker discrepancy .................................................. 4-18
general input ................................................................... 4-15
ground switch status ........................................................ 4-19
remote reset ................................................................... 4-16
sequential trip ................................................................. 4-17
specifications .................................................................... 1-4
tachometer ..................................................................... 4-18
test input ........................................................................ 4-16
testing ..............................................................................7-7
thermal reset ................................................................... 4-16
DIMENSIONS ..................................................................... 2-1
DISPLAY ............................................................................ 3-1
DISTANCE ELEMENTS .................................................... 4-43
DNP
device profile document .................................................... 6-39
implementation table ........................................................ 6-41
point lists ...................................................... 6-43, 6-45, 6-46
setpoints .......................................................................... 4-8
DUAL SETPOINTS ............................................. 4-6, 4-16, 6-9
489 Generator Management Relay
1
INDEX
general ............................................................................ 1-5
RTD ........................................................................1-4, 2-12
voltage ....................................................................1-4, 2-11
E
ELECTRICAL INTERFACE ................................................. 6-1
EMERGENCY RESTARTS ................................................ 4-16
ENTERING +/– SIGNS ....................................................... 3-3
ENTERING ALPHANUMERIC TEXT .................................... 3-2
ENVIRONMENT ................................................................. 1-7
ERROR RESPONSES ........................................................ 6-7
EU .................................................................................... C-2
EU Declaration of Conformity ............................................. C-2
EVENT RECORD
cause of events ............................................................... 5-24
EVENT RECORDER ........................ 3-16, 4-11, 4-16, 5-23, 6-8
F
FACTORY SERVICE ........................................................ 4-82
FAULT SETUP ................................................................. 4-80
FEATURES .......................................................... 1-1, 1-2, 1-7
FIELD-BREAKER DISCREPANCY ...................................... 1-5
FIRMWARE, UPGRADING .................................................. 3-8
FLASH MESSAGES ......................................................... 5-27
FLEXCURVE .................................................................... 4-23
FLOW .............................................................................. 2-11
FREQUENCY TRACKING ................................................... 1-4
FUSE ................................................................................. 1-8
G
GENERAL COUNTERS .................................................... 5-22
GENERAL INPUTS .................................................... 1-5, 4-15
GENERATOR INFORMATION ........................................... 4-11
GENERATOR LOAD ......................................................... 5-18
GENERATOR PARAMETERS ........................................... 4-13
GENERATOR STATUS ....................................................... 5-3
GROUND CT
burden ............................................................................. 1-4
setpoint .......................................................................... 4-12
withstand .......................................................................... 1-4
GROUND CURRENT ACCURACY TEST .................... 7-4, 7-13
GROUND CURRENT INPUT ............................................. 2-10
GROUND DIRECTIONAL ........................................... 4-31, A-3
GROUND FAULT CTs ....................................................... A-7
GROUND OVERCURRENT ........................................ 4-29, A-2
GROUND SWITCH STATUS ............................................. 4-19
H
HIGH-SET PHASE OVERCURRENT ................................. 4-32
HI-POT ............................................................................ 2-15
HOT/COLD CURVE RATIO ............................................... 4-67
I
IAC CURVES ............................................................ 4-22, B-6
IDENTIFICATION ............................................................... 2-2
IEC CURVES .......................................................... 4-22, B-10
INADVERTENT ENERGIZATION ............................... 1-6, 4-25
INJECTION TEST SETUP ................................. 7-2, 7-12, 7-15
INPUTS
analog ..................................................................... 1-4, 2-11
current ............................................................. 1-4, 2-9, 2-10
digital ...................................................................... 1-4, 2-11
2
INSERTION ....................................................................... 2-3
INSTALLATION ................................................................. 2-3
IRIG-B .......................................................................2-13, 4-9
K
KEYPAD ............................................................................ 3-2
L
LAST TRIP DATA ............................... 4-11, 4-16, 5-3, 5-6, 5-9
LEARNED PARAMETERS .................................................4-16
LEDs .......................................................................... 3-1, 3-2
LONG-TERM STORAGE .................................................... 1-8
LOOP POWERED TRANSDUCERS ...................................2-11
LOOPBACK TEST ............................................................. 6-5
LOSS OF EXCITATION ..............................................1-7, 4-42
LOSS OF LOAD ................................................................. 3-2
LOW FORWARD POWER .................................................4-48
M
MACHINE COOLING .........................................................4-66
MEMORY MAP
data formats ....................................................................6-34
description ....................................................................... 6-8
information ....................................................................... 6-8
Modbus ..........................................................................6-10
user-definable .................................................................. 6-8
MESSAGE SCRATCHPAD ................................................4-10
METERING
current ............................................................................5-13
demand ...................................................................1-5, 5-17
Mvarh ........................................................... 4-11, 4-16, 5-15
MWh ............................................................ 4-11, 4-16, 5-15
power ......................................................................1-5, 5-15
specifications ................................................................... 1-2
voltage ...........................................................................5-14
MODBUS
description ....................................................................... 6-1
execute operation ............................................................. 6-4
function code 03 ............................................................... 6-3
function code 04 ............................................................... 6-3
function code 05 ............................................................... 6-4
function code 06 ............................................................... 6-4
function code 07 ............................................................... 6-5
function code 08 ............................................................... 6-5
function code 16 ............................................................... 6-6
loopback test .................................................................... 6-5
performing commands ....................................................... 6-7
read actual values ............................................................. 6-3
read device status ............................................................. 6-5
read setpoints ................................................................... 6-3
store multiple setpoints ...................................................... 6-6
store single setpoint .......................................................... 6-4
MODBUS FUNCTIONS ...................................................... 6-3
MODEL INFORMATION ....................................................5-25
MODEL SETUP ................................................................4-56
MOTOR STARTS ..............................................................4-16
MOTOR TRIPS .................................................................4-16
MVA DEMAND ......................................................... 4-72, 5-17
MVAR DEMAND ...................................................... 4-72, 5-17
Mvarh METERING .......................................... 4-11, 4-16, 5-15
MW DEMAND .......................................................... 4-72, 5-17
MWh METERING ............................................ 4-11, 4-16, 5-15
489 Generator Management Relay
GE Multilin
INDEX
N
NEGATIVE SEQUENCE CURRENT ACCURACY TEST ....... 7-5
NEGATIVE SEQUENCE OVERCURRENT ......................... 4-27
NEGATIVE-SEQUENCE CURRENT .................................. 5-13
NEUTRAL CURRENT ACCURACY TEST ............................ 7-4
NEUTRAL OVERVOLTAGE ....................................... 4-39, A-1
NEUTRAL UNDERVOLTAGE ............................................ 4-40
NEUTRAL VOLTAGE ACCURACY TEST .................... 7-4, 7-13
O
OFFLINE OVERCURRENT ............................................... 4-24
OPEN DELTA .................................................................. 2-11
OPEN DELTA CONNECTED VTs ...................................... 4-41
OPEN RTD SENSOR ....................................................... 4-54
ORDER CODES ................................................................. 1-4
OUTPUT CURRENT ACCURACY TEST .............................. 7-3
OUTPUT RELAY LEDs ....................................................... 3-2
OUTPUT RELAYS
R1 TRIP ......................................................................... 2-13
R2 AUXILIARY ................................................................ 2-13
R3 AUXILIARY ................................................................ 2-13
R4 ALARM ..................................................................... 2-13
R6 SERVICE .................................................................. 2-13
setpoints ........................................................................ 4-20
specifications .................................................................... 1-5
testing ............................................................................. 7-8
wiring ............................................................................ 2-13
OUTPUTS
analog .................................................................... 1-5, 2-12
OVERCURRENT
ground ........................................................................... 4-29
ground directional ........................................................... 4-31
high-set ......................................................................... 4-32
negative-sequence .......................................................... 4-27
phase ............................................................................ 4-26
phase differential ............................................................ 4-30
setpoints ........................................................................ 4-24
specifications .................................................................... 1-6
TOC .............................................................................. 4-21
OVERCURRENT ALARM .................................................. 4-24
OVERCURRENT CURVES
ANSI ............................................................................... B-1
characteristics ................................................................ 4-21
definite time ..................................................................... B-5
graphs ............................................................................. B-1
IAC ........................................................................ 4-22, B-6
IEC ...................................................................... 4-22, B-10
OVERFREQUENCY .................................................. 1-7, 4-38
OVERLOAD CURVES
custom ........................................................................... 4-60
definite time ................................................................... 4-23
testing ............................................................................. 7-9
OVERVOLTAGE ....................................................... 1-6, 4-34
P
PACKAGING ...................................................................... 1-8
PARAMETER AVERAGES ................................................ 5-18
PARITY ............................................................................. 4-8
PASSCODE ......................................................... 3-3, 4-1, 4-7
PEAK DEMAND .......................................................4-11, 5-17
PHASE CT PRIMARY ...............................................4-12, 4-13
PHASE CTs ....................................................................... A-8
PHASE CURRENT INPUTS ................................................ 2-9
PHASE DIFFERENTIAL ................................................... 4-30
PHASE DIFFERENTIAL TRIP TEST ................................. 7-14
PHASE OVERCURRENT .................................................. 4-26
GE Multilin
PHASE REVERSAL .......................................................... 4-36
PHASE REVERSAL TEST ................................................. 7-12
PHASORS ........................................................................ 3-15
POSITIVE-SEQUENCE CURRENT .................................... 5-13
POWER DEMAND ............................................................ 4-72
POWER MEASUREMENT CONVENTIONS ........................ 4-45
POWER MEASUREMENT TEST ....................................... 7-10
POWER METERING ........................................... 1-5, 1-7, 5-15
POWER SUPPLY ........................................................ 1-4, 2-9
POWER SYSTEM ............................................................. 4-13
PRE-FAULT SETUP ......................................................... 4-79
PREFERENCES ................................................................. 4-7
PRESSURE ...................................................................... 2-11
PRODUCT IDENTIFICATION .............................................. 2-2
PRODUCTION TESTS ........................................................ 1-8
PROTECTION FEATURES .................................................. 1-2
PROXIMITY PROBE ......................................................... 2-11
PULSE OUTPUT ....................................................... 1-7, 4-74
R
REACTIVE POWER .......................................................... 4-46
REACTIVE POWER TEST ................................................ 7-11
REAL TIME CLOCK ................................................... 4-9, 5-12
RELAY ASSIGNMENT PRACTICES .................................... 4-5
RELAY RESET MODE ...................................................... 4-20
REMOTE RESET .............................................................. 4-16
RESETTING THE 489 ....................................................... 4-20
RESIDUAL GROUND CONNECTION ................................. 2-10
REVERSE POWER ........................................................... 4-47
REVISION HISTORY ......................................................... C-1
RS232 COMMUNICATIONS .................................. 3-2, 4-8, 6-1
RS485 COMMUNICATIONS ................................ 2-14, 4-8, 6-1
RTD
actual values .......................................................... 5-16, 5-18
maximums .................................................... 4-11, 4-16, 5-18
sensor connections .......................................................... 2-12
setpoints .............................................. 4-50, 4-51, 4-52, 4-53
specifications ............................................................. 1-4, 1-7
testing ..............................................................................7-6
RTD ACCURACY TEST ...................................................... 7-6
RTD BIAS ........................................................................ 4-67
RTD MAXIMUMS .............................................................. 5-18
RTD SENSOR, OPEN ....................................................... 4-54
RTD SHORT/LOW TEMPERATURE .................................. 4-54
RTD TYPES ..................................................................... 4-49
RUNNING HOUR SETUP .................................................. 4-74
RUNNING HOURS ........................................................... 4-16
S
SEQUENTIAL TRIP ................................................... 1-5, 4-17
SERIAL PORTS ................................................................. 4-8
SERIAL START/STOP INITIATION .................................... 4-13
SERVICE RELAY ............................................................. 2-13
SETPOINT ENTRY ............................................................. 3-3
SETPOINT MESSAGE MAP ................................................ 4-1
SETPOINTS
dual setpoints .................................................................... 4-6
entering through software ................................................. 3-10
loading from a file .............................................................. 3-9
messages ......................................................................... 4-1
printing ........................................................................... 3-11
saving to a file ................................................................... 3-8
upgrading setpoint files .................................................... 3-10
SIMULATION MODE ......................................................... 4-78
SINGLE LINE DIAGRAM ..................................................... 1-1
SOFTWARE
489 Generator Management Relay
3
INDEX
configuration ..................................................................... 3-7
installation ........................................................................ 3-5
loading setpoints ............................................................... 3-9
phasors .......................................................................... 3-15
printing setpoints/actual values ......................................... 3-11
requirements ..................................................................... 3-4
startup ............................................................................. 3-7
trending .......................................................................... 3-12
troubleshooting ............................................................... 3-17
upgrade ............................................................................ 3-5
upgrading firmware ............................................................ 3-8
upgrading setpoint files .................................................... 3-10
SPECIFICATIONS .............................................................. 1-4
SPEED ............................................................................ 5-17
STARTER
information ..................................................................... 4-11
operations ...................................................................... 4-16
status ............................................................................ 4-14
STATOR GROUND FAULT PROTECTION .......................... A-1
STATUS LEDs ................................................................... 3-1
TIME OVERCURRENT CURVES ........................................ B-1
TIMERS ...........................................................................5-22
TIMING ............................................................................. 6-2
TOC CHARACTERISTICS .................................................4-21
TOC CURVES ................................................................... B-1
TRACE MEMORY .............................................................. 6-9
TRENDING .......................................................................3-12
TRIP COIL MONITOR .......................................................4-70
TRIP COIL SUPERVISION .......................................... 1-4, 7-7
TRIP COUNTER ............................................. 4-11, 4-69, 5-20
TRIP PICKUPS .................................................................. 5-6
TRIP RELAY ............................................................ 2-13, 4-20
TRIP TIME ON OVERLOAD, ESTIMATED ........................... 5-3
TRIPS ............................................................................... 4-5
TYPE TESTS ..................................................................... 1-8
TYPICAL WIRING DIAGRAM .............................................. 2-7
U
T
TACHOMETER ................................................. 1-5, 4-18, 5-17
TEMPERATURE ............................................................... 5-16
TEMPERATURE DISPLAY .................................................. 4-8
TERMINAL LAYOUT ........................................................... 2-5
TERMINAL LIST ................................................................. 2-6
TERMINAL LOCATIONS ..................................................... 2-5
TERMINAL SPECIFICATIONS ............................................ 1-5
TEST ANALOG OUTPUT .................................................. 4-81
TEST INPUT .................................................................... 4-16
TEST OUTPUT RELAYS ................................................... 4-81
TESTS
differential current accuracy ................................................ 7-4
ground current accuracy ............................................ 7-4, 7-13
list ................................................................................... 7-1
negative-sequence current accuracy .................................... 7-5
neutral current accuracy ..................................................... 7-4
neutral voltage accuracy ............................................ 7-4, 7-13
output current accuracy ...................................................... 7-3
output relays ..................................................................... 7-8
overload curves ................................................................. 7-9
phase current accuracy ...................................................... 7-3
power measurement ......................................................... 7-10
production tests ................................................................. 1-8
reactive power ................................................................ 7-11
RTD accuracy ................................................................... 7-6
secondary injection setup ................................................... 7-2
voltage input accurcay ........................................................ 7-3
voltage phase reversal ..................................................... 7-12
THERMAL CAPACITY USED .............................................. 5-3
THERMAL ELEMENTS ..................................................... 4-68
THERMAL MODEL
machine cooling .............................................................. 4-66
setpoints ........................................................................ 4-55
specifications .................................................................... 1-7
unbalance bias ................................................................ 4-65
THERMAL RESET ............................................................ 4-16
THIRD HARMONIC VOLTAGE ........................................... A-5
TIME ........................................................................ 4-9, 5-12
4
UNBALANCE BIAS ...........................................................4-65
UNDERFREQUENCY ........................................................4-37
UNDERVOLTAGE ......................................................1-6, 4-33
USER DEFINABLE MEMORY MAP ..................................... 6-8
V
VIBRATION ......................................................................2-11
VOLTAGE DEPENDENT OVERLOAD CURVE ....................4-61
VOLTAGE INPUTS
description ......................................................................2-11
specifications ................................................................... 1-4
testing ............................................................................. 7-3
VOLTAGE METERING ......................................................5-14
VOLTAGE RESTRAINED OVERCURRENT
setpoints .........................................................................4-26
testing ............................................................................7-16
VOLTAGE SENSING .........................................................4-12
VOLTS/HERTZ .................................................................4-35
VT FUSE FAILURE ...........................................................4-71
VT RATIO .........................................................................4-12
VTFF ................................................................................4-71
VTs
open delta .......................................................................4-41
setpoints .........................................................................4-12
wye connected .................................................................4-41
W
WARRANTY .............................................................. C-1, C-3
WAVEFORM CAPTURE .................................... 3-14, 4-19, 6-9
WIRING DIAGRAM ............................................................ 2-8
WITHDRAWAL .................................................................. 2-3
WYE ................................................................................2-11
WYE CONNECTED VTs ....................................................4-41
489 Generator Management Relay
GE Multilin
FIGURE 1–1: SINGLE LINE DIAGRAM ......................................................................................................................................................... 1
FIGURE 2–1: 489 DIMENSIONS ................................................................................................................................................................. 1
FIGURE 2–2: DRAWOUT UNIT SEAL .......................................................................................................................................................... 1
FIGURE 2–3: CASE AND UNIT IDENTIFICATION LABELS ............................................................................................................................... 2
FIGURE 2–4: BEND UP MOUNTING TABS................................................................................................................................................... 3
FIGURE 2–5: PRESS LATCH TO DISENGAGE HANDLE ................................................................................................................................. 3
FIGURE 2–6: ROTATE HANDLE TO STOP POSITION .................................................................................................................................... 4
FIGURE 2–7: SLIDE UNIT OUT OF CASE .................................................................................................................................................... 4
FIGURE 2–8: TERMINAL LAYOUT ............................................................................................................................................................... 5
FIGURE 2–9: TYPICAL WIRING DIAGRAM ................................................................................................................................................... 7
FIGURE 2–10: TYPICAL WIRING (DETAIL) .................................................................................................................................................. 8
FIGURE 2–11: CONTROL POWER CONNECTION ......................................................................................................................................... 9
FIGURE 2–12: RESIDUAL GROUND CT CONNECTION ............................................................................................................................... 10
FIGURE 2–13: CORE BALANCE GROUND CT INSTALLATION ..................................................................................................................... 10
FIGURE 2–14: LOOP POWERED TRANSDUCER CONNECTION .................................................................................................................... 11
FIGURE 2–15: RTD WIRING ................................................................................................................................................................... 12
FIGURE 2–16: RS485 COMMUNICATIONS WIRING ................................................................................................................................... 14
FIGURE 2–17: TESTING THE 489 FOR DIELECTRIC STRENGTH ................................................................................................................. 15
FIGURE 3–1: 489 LED INDICATORS .......................................................................................................................................................... 1
FIGURE 3–2: 489 KEYPAD ........................................................................................................................................................................ 2
FIGURE 3–3: GE MULTILIN WELCOME SCREEN ......................................................................................................................................... 6
FIGURE 3–4: COMMUNICATION/COMPUTER DIALOG BOX ........................................................................................................................... 7
FIGURE 3–5: GRAPH ATTRIBUTE WINDOW – TRENDING ........................................................................................................................... 12
FIGURE 3–6: TRENDING ......................................................................................................................................................................... 13
FIGURE 3–7: TRENDING FILE SETUP ....................................................................................................................................................... 13
FIGURE 3–8: WAVEFORM CAPTURE ........................................................................................................................................................ 14
FIGURE 3–9: PHASORS .......................................................................................................................................................................... 15
FIGURE 3–10: 489PC EVENT RECORDER ............................................................................................................................................... 16
FIGURE 4–1: INADVERTENT ENERGIZATION ............................................................................................................................................. 25
FIGURE 4–2: VOLTAGE RESTRAINT CHARACTERISTIC .............................................................................................................................. 27
FIGURE 4–3: NEGATIVE SEQUENCE INVERSE TIME CURVES .................................................................................................................... 28
FIGURE 4–4: DIFFERENTIAL ELEMENTS ................................................................................................................................................... 31
FIGURE 4–5: GROUND DIRECTIONAL DETECTION .................................................................................................................................... 32
FIGURE 4–6: NEUTRAL OVERVOLTAGE DETECTION ................................................................................................................................. 40
FIGURE 4–7: LOSS OF EXCITATION R-X DIAGRAM ................................................................................................................................... 43
FIGURE 4–8: DISTANCE ELEMENT SETUP................................................................................................................................................ 44
FIGURE 4–9: POWER MEASUREMENT CONVENTIONS ............................................................................................................................... 45
FIGURE 4–10: TYPICAL TIME-CURRENT AND THERMAL LIMIT CURVES (ANSI/IEEE C37.96) .................................................................... 55
FIGURE 4–11: 489 STANDARD OVERLOAD CURVES ................................................................................................................................ 58
FIGURE 4–12: CUSTOM CURVE EXAMPLE ............................................................................................................................................... 60
FIGURE 4–13: THERMAL LIMITS FOR HIGH INERTIAL LOAD ....................................................................................................................... 61
FIGURE 4–14: VOLTAGE DEPENDENT OVERLOAD CURVES ...................................................................................................................... 62
FIGURE 4–15: VOLTAGE DEPENDENT OVERLOAD PROTECTION CURVES .................................................................................................. 63
FIGURE 4–16: VOLTAGE DEPENDENT O/L PROTECTION AT 80% AND 100% VOLTAGE ............................................................................. 64
FIGURE 4–17: THERMAL MODEL COOLING .............................................................................................................................................. 66
FIGURE 4–18: RTD BIAS CURVE ............................................................................................................................................................ 68
FIGURE 4–19: TRIP COIL SUPERVISION .................................................................................................................................................. 70
FIGURE 4–20: VT FUSE FAILURE LOGIC ................................................................................................................................................. 71
FIGURE 4–21: ROLLING DEMAND (15 MINUTE WINDOW) ......................................................................................................................... 73
FIGURE 4–22: PULSE OUTPUT ............................................................................................................................................................... 74
FIGURE 7–1: SECONDARY CURRENT INJECTION TESTING .......................................................................................................................... 2
FIGURE 7–2: SECONDARY INJECTION SETUP #2...................................................................................................................................... 12
FIGURE 7–3: SECONDARY INJECTION TEST SETUP #3............................................................................................................................. 15
FIGURE A–1: STATOR GROUND FAULT PROTECTION ................................................................................................................................. 1
FIGURE A–2: PARALLEL GENERATORS WITH COMMON GROUNDING IMPEDANCE......................................................................................... 2
FIGURE A–3: GROUND OVERCURRENT ELEMENT WITH DIFFERENT CURRENT SOURCE SIGNALS ................................................................. 3
FIGURE A–4: GROUND DIRECTIONAL ELEMENT POLARITIES AND PLANE OF OPERATION ............................................................................. 3
FIGURE A–5: GROUND DIRECTIONAL ELEMENT CONCEPTUAL ARRANGEMENT ............................................................................................ 4
FIGURE B–1: ANSI MODERATELY INVERSE CURVES ................................................................................................................................. 1
FIGURE B–2: ANSI NORMALLY INVERSE CURVES ..................................................................................................................................... 2
FIGURE B–3: ANSI VERY INVERSE CURVES ............................................................................................................................................. 3
FIGURE B–4: ANSI EXTREMELY INVERSE CURVES .................................................................................................................................... 4
FIGURE B–5: DEFINITE TIME CURVES ....................................................................................................................................................... 5
FIGURE B–6: IAC SHORT INVERSE CURVES.............................................................................................................................................. 6
FIGURE B–7: IAC INVERSE CURVES ......................................................................................................................................................... 7
FIGURE B–8: IAC VERY INVERSE CURVES ................................................................................................................................................ 8
FIGURE B–9: IAC EXTREME INVERSE CURVES .......................................................................................................................................... 9
FIGURE B–10: IEC CURVES A (BS142) ................................................................................................................................................. 10
FIGURE B–11: IEC CURVES B (BS142) ................................................................................................................................................. 11
FIGURE B–12: IEC CURVES C (BS142) ................................................................................................................................................. 12
TABLE: 1–1 TRIP AND ALARM PROTECTION FEATURES .............................................................................................................................. 2
TABLE: 1–2 METERING AND ADDITIONAL FEATURES .................................................................................................................................. 2
TABLE: 1–3 489 ORDER CODES ............................................................................................................................................................... 3
TABLE: 2–1 489 TERMINAL LIST ............................................................................................................................................................... 6
TABLE: 4–1 489 OVERCURRENT CURVE TYPES ...................................................................................................................................... 21
TABLE: 4–2 ANSI INVERSE TIME CURVE CONSTANTS ............................................................................................................................. 21
TABLE: 4–3 IEC (BS) INVERSE TIME CURVE CONSTANTS ....................................................................................................................... 22
TABLE: 4–4 IAC INVERSE TIME CURVE CONSTANTS................................................................................................................................ 22
TABLE: 4–5 FLEXCURVE™ TRIP TIMES .................................................................................................................................................. 23
TABLE: 4–6 RTD TEMPERATURE VS. RESISTANCE .................................................................................................................................. 49
TABLE: 4–7 489 STANDARD OVERLOAD CURVE MULTIPLIERS .................................................................................................................. 59
TABLE: 4–8 ANALOG OUTPUT PARAMETER SELECTION............................................................................................................................ 76
TABLE: 5–1 CAUSE OF EVENTS .............................................................................................................................................................. 24
TABLE: 5–2 FLASH MESSAGES ............................................................................................................................................................... 27
TABLE: 6–1 489 MEMORY MAP .............................................................................................................................................................. 10
TABLE: 6–2 DATA FORMATS ................................................................................................................................................................... 34
TABLE: 6–3 DNP IMPLEMENTATION TABLE .............................................................................................................................................. 41
TABLE: 6–4 DEFAULT VARIATIONS .......................................................................................................................................................... 42
TABLE: 6–5 BINARY INPUT POINTS ......................................................................................................................................................... 43
TABLE: 6–6 BINARY OUTPUT POINT LIST ................................................................................................................................................ 45
TABLE: 6–7 COUNTERS POINT LIST ........................................................................................................................................................ 46
TABLE: 6–8 ANALOG INPUTS POINT LIST................................................................................................................................................. 47
TABLE: 7–1 NEUTRAL AND GROUND CURRENT TEST RESULTS .................................................................................................................. 4
TABLE: 7–2 DIFFERENTIAL CURRENT TEST RESULTS ................................................................................................................................ 4
TABLE: A–1 DETECTION ELEMENT STATUS ............................................................................................................................................... 4
TABLE: C–1 REVISION HISTORY ............................................................................................................................................................... 1
TABLE: C–2 UPDATES FOR 489 MANUAL REVISION EC ............................................................................................................................. 1
Was this manual useful for you? yes no
Thank you for your participation!

* Your assessment is very important for improving the work of artificial intelligence, which forms the content of this project

Download PDF

advertising